STATE OF MICHIGAN
BEFORE THE MICHIGAN PUBLIC SERVICE COMMISSION
*****
In the matter of the application of
DTE ELECTRIC COMPANY for approval of
certificates of necessity pursuant to MCL 460.6s, as
amended, in connection with the addition of a natural
gas combined cycle generating facility to its
generation fleet and for related accounting and
ratemaking authorizations.

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Case No. U-18419

At the April 27, 2018 meeting of the Michigan Public Service Commission in Lansing,
Michigan.

PRESENT: Hon. Sally A. Talberg, Chairman
Hon. Norman J. Saari, Commissioner
Hon. Rachael A. Eubanks, Commissioner

OPINION AND ORDER
I.

HISTORY OF PROCEEDINGS

On June 30, 2017, DTE Electric Company (DTE Electric) submitted a notice of intent to file
an application requesting approval of certificates of necessity (CONs) pursuant to MCL 460.6s and
the May 11, 2017 order in Case No. U-15896 (May 11 order). On July 12, 2017, the Commission
issued an order in this case (July 12 order), providing guidance to the Administrative Law Judge
because: “MCL 460.6s, as amended by Act 341, has not yet been subject to scrutiny or
interpretation by the Commission . . . and because certain provisions of the amended version of
MCL 460.6s involve novel procedural requirements.” July 12 order, p. 2.
On July 31, 2017, DTE Electric filed an application, with supporting testimony and exhibits,

 requesting CONs for the construction of a 1,100 megawatt (MW) natural gas combined cycle
(NGCC) electric generation facility at the company’s Belle River Power Plant site. Specifically,
DTE Electric seeks CONs that: (1) the power to be supplied by the proposed project is needed;
(2) the size, fuel type, and other design characteristics of the proposed project represent the most
reasonable and prudent means of meeting that power need; and (3) the estimated $989 million
capital costs of, and the financing plan for, the proposed project will be recoverable in rates from
DTE Electric’s customers.
On September 7, 2017, a prehearing conference was held before Administrative Law Judge
Suzanne D. Sonneborn (ALJ). At the prehearing conference, the ALJ granted intervention to the
Michigan Department of the Attorney General (Attorney General); the Association of Businesses
Advocating Tariff Equity (ABATE); City of Ann Arbor (Ann Arbor); Energy Michigan;
International Transmission Company (ITC); Midland Cogeneration Venture Limited Partnership
(MCV); Michigan Environmental Council, Natural Resources Defense Council, and Sierra Club
(together, MEC/NRDC/SC); Ecology Center, Solar Energy Industries Association, Union of
Concerned Scientists, Vote Solar, and Environmental Law & Policy Center, (collectively, ELPC et
al.); and the Michigan Energy Innovation Business Council (EIBC). The Commission Staff
(Staff) also participated in the proceeding.
On September 7, 2017, ABATE, MEC/NRDC/SC, the Attorney General, and the MCV
(Movants) filed a joint motion to compel discovery of DTE Electric’s ABB Strategist and ABB
PROMOD computer models and associated workpapers or, alternatively requested that the ALJ
grant their joint motion in limine to exclude all testimony and exhibits that rely on the modeling or
related workpapers. On October 2, 2017, the Staff and ELPC et al. filed responses in support of
the motions, and DTE Electric filed a response opposing the motions along with a cross-motion

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 requesting a protective order. On October 5, 2017, the ALJ conducted a hearing on the motions,
and on October 10, 2017, she issued a ruling (October 10 ruling) granting Movants’ joint motion
to compel and denying the joint motion in limine. The ALJ held in abeyance DTE Electric’s
cross-motion for a protective order pending modifications of that order to comport with the
remainder of her ruling.
On October 18, 2017, Movants filed a joint motion to clarify or enforce the ALJ’s October 10
ruling, and a motion to modify the schedule. Alternatively, Movants renewed their joint motion in
limine to exclude portions of DTE Electric’s testimony and exhibits. On October 23, 2017, DTE
Electric filed a response opposing the joint motions. The ALJ conducted a hearing on the motions
on October 24, 2017, and she granted the joint motion to enforce the October 10 ruling. On
October 30, 2017, the ALJ entered a protective order.
On December 1, 2017, the Staff moved to extend the schedule beyond the 270-day statutory
deadline. On December 4, 2017, DTE Electric filed a motion to limit discovery of engineering,
procurement, and construction (EPC) bids. On December 7, 2017, MEC/NRDC/SC filed a
response supporting the Staff’s motion to extend the schedule. On that same date, DTE Electric
filed a response opposing the Staff’s motion, and ABATE filed a response in support of the Staff’s
motion and opposing DTE Electric’s motion. The Staff also filed a response opposing DTE
Electric’s motion.
On December 11, 2017, the ALJ held a hearing on DTE Electric’s and the Staff’s motions, and
on December 12, 2017, the ALJ issued a ruling granting the requested extension. DTE Electric
appealed the ruling, and on January 23, 2018, the Commission issued an order reversing the ALJ

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 and finding that, to meet the statutory deadline, the Commission would read the record. 1
On February 7, 2018, the Staff, the Attorney General, and ABATE filed motions to strike, all
or in part, certain rebuttal testimony and exhibits filed by DTE Electric witnesses. On February 9,
2018, DTE Electric filed responses opposing the motions. The ALJ denied ABATE’s motion to
strike and granted the Staff’s and Attorney General’s motions. 5 Tr 1407-1409, 1418-1425.
Evidentiary hearings were held on February 14-16, 2018. On February 22, 2018, DTE
Electric filed a request for corrections to the transcript, which was unopposed and which the ALJ
granted on March 1, 2018. DTE Electric, the Staff, the Attorney General, ABATE,
MEC/NRDC/SC, ELPC et al. and EIBC filed initial briefs on March 2, 2018. On March 12, 2018,
DTE Electric, the Staff, ABATE, MEC/NRDC/SC, ELPC et al., and Ann Arbor filed reply briefs.
The record in this proceeding consists of 2,617 pages of transcript and 471 exhibits admitted into
evidence. All or part of several exhibits and portions of the transcript were filed under seal and are
not available in the public record.

The Commission seeks to clarify that it agrees with the ALJ’s legal conclusion in her
December 12 ruling regarding the statutory deadline under applicable law. As a matter of policy,
however, the Commission has prioritized the timely issuance of orders to comply with statutory
directives and provide regulatory certainty. The Commission recognizes that exceptional
circumstances may present themselves making it impossible or inappropriate to meet statutory
deadlines in certain cases, even with the Commission doing all it can to expedite the process.
While the Commission did not find compelling circumstances to grant an extension in this
proceeding and was able to comply with the 270-day deadline by reading the record, the
Commission is disturbed by DTE Electric’s discovery tactics and interference with other parties’
abilities to obtain data germane to the issues in this proceeding in a timely manner. As outlined in
its guidance for upcoming integrated resource plan (IRP) proceedings under section 6t, the
Commission stresses the importance of engaging with technical stakeholders to provide
transparency around modeling approaches, assumptions, and data sources and to freely exchange
underlying modeling data for analysis by parties. While the Commission expects a more
cooperative approach in the future, it would not rule out sanctions for discovery abuses as
provided under MCR 2.313 and Mich Admin Code, R 792.10423.
1

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 II. LEGAL STANDARDS

As explained previously, DTE Electric requested three CONs under MCL 460.6s(3)(a), (b),
and (d). MCL 460.6s provides:
(1) An electric utility that proposes to construct an electric generation facility . . .
may submit an application to the commission seeking a certificate of necessity for
that construction . . . if that construction . . . costs $100,000,000.00 or more and a
portion of the costs would be allocable to retail customers in this state.
***
(3) An electric utility submitting an application under this section may request 1 or
more of the following:
(a) A certificate of necessity that the power to be supplied as a result of the
proposed construction, investment, or purchase is needed.
(b) A certificate of necessity that the size, fuel type, and other design characteristics
of the existing or proposed electric generation facility . . . represent the most
reasonable and prudent means of meeting that power need.
***
(d) A certificate of necessity that the estimated . . . capital costs of and the financing
plan for the . . . proposed electric generation facility, including, but not limited to,
the costs of siting and licensing a new facility and the estimated cost of power from
the new . . . electric generation facility, will be recoverable in rates from the electric
utility’s customers subject to subsection (4)(c).
DTE Electric’s application for a CON for new construction was filed at the utility’s discretion.
Unlike the circumstance with pipelines regulated under 1929 PA 9 or 1929 PA 16, or a certificate
of public convenience and necessity under 1929 PA 69, a utility may build generation without
requesting, or receiving, a CON from the Commission, if the utility determines that it is reasonable
to do so. The lack of a CON will not prejudice the recovery of reasonable and prudent costs of the
plant through rate cases, once the plant is “used and useful.”
But under this traditional approach, there are inherent risks—for both utilities and
ratepayers—of waiting years for regulatory determinations on the need, preferred technology
relative to alternatives, and costs, given the piecemeal nature of cost review and other regulatory
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 determinations. In contrast, the CON framework, with the support of an IRP to evaluate need,
options, and costs, allows for a thorough and holistic examination of these issues prior to a utility
proceeding with the construction of a large capital project. The utility benefits because the CON
mitigates risk by providing up-front assurance of cost recovery up to the amount approved in the
CON and the ability to include financing costs in rates before the plant is considered used and
useful in the provision of utility service. Ratepayers can benefit because any costs incurred over
the approved amount are presumed to be imprudent. MCL 460.6s(9). While the utility could still
request recovery of such costs, it would have to overcome this evidentiary presumption. Since the
CON statute was enacted, no utility has pursued a large investment in new generation or upgrades
to existing facilities 2 without seeking a CON. 3 Going forward, CONs are now required for
generation projects 225 MW and above as part of an IRP under section 6t.
The Commission’s responsibilities in evaluating an application are outlined in Section 6s(4),
MCL 460.6s(4):
Within 270 days after the filing of an application under this section, . . . the
commission shall issue an order granting or denying the requested certificate of
necessity. The commission shall hold a hearing on the application . . . as a
contested case . . . The commission shall permit reasonable discovery before and
during the hearing in order to assist parties and interested persons in obtaining
evidence concerning the application, including, but not limited to, the
reasonableness and prudence of the construction . . . for which the certificate of
necessity has been requested. The commission shall grant the request if it
determines all of the following:
(a) That the electric utility has demonstrated a need for the power that would be
supplied by the . . . proposed electric generation facility . . . through its approved
integrated resource plan under section 6t or subsection (11).
2

Except environmental upgrades, which are not eligible for a CON under the law.

3

Prior to this DTE Electric application, three CONs have been requested; of these, two have
been granted by the Commission (Indiana Michigan Power Company’s Cook Nuclear Plant
overhaul and Upper Michigan Energy Resources Corporation new gas plant) and one was
withdrawn (Consumers Energy’s Thetford gas plant).
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 (b) The information supplied indicates that the . . . proposed electric generation
facility will comply with all applicable state and federal environmental standards,
laws, and rules.
(c) The estimated cost of power from the . . . proposed electric generation facility . .
. is reasonable. The commission shall find that the cost is reasonable if, in the
construction . . . to the extent it is commercially practicable, the estimated costs are
the result of competitively bid engineering, procurement, and construction
contracts[.] Up to 150 days after an electric utility makes its initial filing, it may
file to update its cost estimates if they have materially changed. No other aspect of
the initial filing may be modified unless the application is withdrawn and refiled.
A utility’s filing updating its cost estimates does not extend the period for the
commission to issue an order granting or denying a certificate of necessity.
(d) The . . . proposed electric generation facility . . . represents the most reasonable
and prudent means of meeting the power need relative to other resource options for
meeting power demand, including energy efficiency programs, electric transmission
efficiencies, and any alternative proposals submitted under this section by existing
suppliers of electric generation capacity under subsection (13) or other intervenors.
(e) To the extent practicable, the construction or investment in a new . . . facility in
this state is completed using a workforce composed of residents of this state as
determined by the commission.
In addition to these statutory obligations, pursuant to MCL 460.6s(10) and (11), the
Commission established requirements for CON filings (CON filing requirements) and guidance
for IRPs (CON IRP guidlines) under Section 6s(11) when Section 6s was first enacted in 2008.
Specifically, on December 23, 2008, in Case No. U-15896 (December 23 order) the Commission
approved CON filing requirements for applications under MCL 460.6s (Exhibit A to the December
23 order) and CON IRP filing guidelines (Exhibit B to the December 23 order). On December 21,
2016, Governor Snyder signed into law Public Act 341 of 2016 (Act 341). This act took effect on
April 20, 2017. Act 341 amended the CON provisions in Section 6s by allowing for certain power
producers to submit alternative proposals to the Commission for consideration. In a subsequent
order, issued on May 11, 2017, the Commission approved updated CON filing requirements
pursuant to Act 341. Thus, the CON filing requirements approved in the May 11 order supersede

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 the CON filing requirements approved in December 23 order, while the previously-approved CON
IRP guidelines remained in effect.
Act 341 also added new IRP provisions in Section 6t. On November 21, 2017, the
Commission issued an order (November 21 order) approving modeling scenarios and parameters
for use in future IRP proceedings under Section 6t. On December 20, 2017, the Commission
issued an order in Case Nos. U-15896 and U-18461 (December 20 order) that approved, inter alia,
comprehensive filing requirements, procedures, and guidelines for IRPs under both Section 6s and
Section 6t, going forward. These IRP guidelines supersede the CON IRP guidelines approved in
the December 23 order.
There is a dispute whether the IRP guidelines, as updated in the December 20 order, apply to
the instant case. As a matter of law, the Commission finds that, because this application predates
the December 20 order by almost six months, these newer requirements do not apply. 4 Parties
have argued that DTE Electric should have anticipated the new requirements because the company
participated in the stakeholder processes in 2017 to develop the new IRP guidelines. The
Commission disagrees that the guidelines were sufficiently developed to provide meaningful
direction, even informally, given that the Commission was still considering important issues like
high/low gas price forecast assumptions and data sources and the pre-filing public engagement
requirement shortly before the Commission’s order in November 2017. Moreover, it is
inappropriate as a regulatory practice to move the so-called “goal posts” on the IRP guidelines
during the course of this proceeding. Thus, the Commission finds that the requirements in section

4

Whatever a company chooses to file in support of its application, the company must still
provide sufficient evidence for the Commission to make the requisite findings under Section 6s(4).
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 6s and the associated CON filing guidelines set forth in the May 2017 order and CON IRP
guidelines approved in the December 23 order apply in this proceeding.
The Commission emphasizes that the IRP guidelines approved in the December 23 order were
intended to provide direction to CON applicants about the types of analyses the Commission
expects to see in the filing. Importantly, simply complying with the requirements in effect at the
time the application was filed does not mean that a request for a CON or an IRP will necessarily
be approved. The Commission must still consider the preponderance of the evidence in making
the requisite findings under Section 6s(4).
For the most part, the parties did not contest DTE Electric’s compliance with the CON filing
requirements set forth in the May 11 order. See, Exhibit A-1. To the extent that any issues were
raised with respect to the CON IRP guidelines in the December 23 order, those issues are
addressed, where applicable, below. See, Exhibits A-1 and A-11.
With respect to whether the IRP filed in this case must be “approved,” MEC/NRDC/SC posit
that:
Section 6s of Act 341 also requires a utility to file an IRP in support of its CON
application. The IRP is a core component of an application for a CON, as
Michigan law expressly links issuing a CON to IRP approval. To receive a CON,
the utility must demonstrate a need for the power that would be supplied by the
proposed plant “through its approved integrated resource plan under section 6t or
subsection (11).” Thus, a prerequisite for a CON is an approved IRP under one of
those two sections. To approve the CON application, the Commission must find
that DTE’s IRP meets the seven requirements outlined in subsection 11 of Section
6s, including:
(f) An analysis of the availability and costs of other electric resources that
could defer, displace, or partially displace the proposed generation facility
or purchased power agreement, including additional renewable energy,
energy efficiency programs, load management, and demand response,
beyond those amounts contained in subdivisions (c) to (e).
Importantly, while Section 6s requires an approved IRP in order to receive a CON,
Section 6s does not include an approval procedure or approval standards for the
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 IRP. Section 6t, on the other hand, does include an approval procedure and
approval standards for an IRP. Therefore[,] the Commission can and should
consider utilizing the approval procedure for Section 6t, including the identification
of recommended changes, for the IRP in this case.
MEC/NRDC/SC’s initial brief, pp. 7-8 (footnotes omitted).
DTE Electric responds:
MEC/NRDC/SC’s proposal is unlawful. MCL 460.6s(4)(a) plainly says “approved
integrated resource plan under section 6t or subsection (11).” (Emphasis added). It
is well established that the statutory term “or” provides a choice between
alternatives. MEC/NRDC/SC’s proposed misreading of MCL 460.6s(4)(a) would
render the emphasized “or subsection (11)” language nugatory and violate the rule
that: “Effect must be given to every word, phrase, and clause in a statute, and the
court must avoid a construction that would render part of the statute surplusage or
nugatory.” Book-Gilbert v Greenleaf, 302 Mich App 538, 541; 840 NW2d
743 (2013); Jenkins v Patel, 471 Mich 158, 167; 684 NW2d 346 (2004) (“Courts
must give effect to every word, phrase, and clause in a statute and avoid an
interpretation that would render any part of the statute surplusage or nugatory[.]”).
DTE Electric’s reply brief, p. 5. DTE Electric further states that it does not yet have an approved
IRP under Section 6t, thus the IRP under Section 6s(11) is the only option in this case.
MEC/NRDC/SC’s argument appears to assume that the word “approved” modifies both an
IRP “under Section 6t” as well as an IRP under “subsection (11)” of Section 6s. The Commission
disagrees that an IRP under MCL 460.6s(11) must be “approved” or, alternatively, that it must be
“approved” in the same manner as an IRP under MCL 460.6t.
First, MEC/NRDC/SC is correct that under the series-qualifier rule of construction, a modifier
placed before a series of nouns or noun phrases generally applies to all of the items in the series.
However, as the United States Supreme Court explained in Lockhart v United States, 136 S Ct
958; 194 L Ed 2d 48 (2016): “Whether a modifier is ‘applicable as much to the first . . . as to the
last’ words in a list, whether a set of items form a ‘single, integrated list,’ and whether the
application of the rule would require acceptance of an ‘unlikely premise’ are fundamentally
contextual questions.” Lockhart, p. 965, quoting Porto Rico Railway, Light & Power Co v Mor,
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 253 US 345, 40 S Ct 516, 64 L Ed 944 (1920) and Paroline v United States, 572 US ____; 134 S
Ct 1710; 188 L Ed 2d 714 (2014).
In Lockhart, the Court affirmed the application of the last antecedent canon, which is the
opposite of the series-qualifier canon: “The [last antecedent] rule provides that ‘a limiting clause
or phrase . . . should ordinarily be read as modifying only the noun or phrase that it immediately
follows.’” Lockhart, p. 962, quoting Barnhart v Thomas, 540 US 20, 26; 124 S Ct 376; 157 L Ed
2d 333 (2003). However, the Court also observed that the application of this canon, or any other
rule of construction, may be controverted by contextual or structural evidence. Lockhart, p. 965.
In the instant case, the Commission finds sufficient indicia in the context of Section 6s and
Section 6t to reject MEC/NRDC/SC’s interpretation that the Commission must “approve” DTE
Electric’s IRP filed under Section 6s(11). Section 6t was enacted specifically for the evaluation,
and approval or disapproval of IRPs, which must be filed by all rate-regulated electric utilities
within two years after April 20, 2017. Section 6t is also mandatory, whereas Section 6s, in this
instance, is optional. Although a CON request may be combined with the IRP under Section 6t,
the central purpose of that proceeding remains the IRP evaluation. Conversely, the purpose of
Section 6s is to provide for the assessment of CON requests for new generation, the purchase or
upgrade of existing facilities, or a PPA, and the IRP serves to support the requested CON. The
Commission further notes that this interpretation is consistent with the CON filing requirements. 5
Moreover, once all rate-regulated utilities have approved IRPs under Section 6t, the IRP under

5

“An integrated resource plan, as required by MCL 460.6s(11) or approved pursuant to
MCL 460.6t, shall be included as an exhibit to the certificate of necessity application. The plan
shall include the items listed in MCL 460.6s(11) and otherwise comply with the Commission’s
standards developed under that section. This subsection does not apply to an electric utility that
has an approved integrated resource plan under MCL 460.6t.” Part IV, Attachment A, May 11
order.
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 Section 6s(11) will no longer be needed. Thus, reading Section 6s in pari materia with Section 6t,
the Commission finds that “approved” only applies to an IRP under Section 6t.
Nevertheless, assuming, arguendo, that the Commission must “approve” an IRP under Section
6s(11), as MEC/NRDC/SC claim, the Commission finds that DTE Electric’s IRP complies with
the requirements under Section 6s as discussed further in this order. 6 In addition, the Commission
disagrees that DTE Electric’s IRP should be evaluated using the same criteria as is provided under
Section 6t. Although DTE Electric submitted a plan for longer than 10 years, and that plan
includes an additional plant in 2029, the Commission must necessarily narrow the scope of its
inquiry to the initial five or six years of the IRP to determine whether the proposed NGCC in 2022
meets the requirements for the findings under MCL 460.6s(4). If the Commission makes those
findings with respect to a project to be in service in five years, the inquiry ends. To do otherwise
would risk turning the CON proceeding under Section 6s into a full IRP proceeding that should be
properly carried out under Section 6t. While the Commission finds the analysis by DTE Electric
and intervenors assisted its understanding of the longer-term options, any recommendations for
additional retirements, renewable energy, EE, DR, or additional fossil generation after 2022 are
largely irrelevant to the issue of whether a CON should be granted for a plant that will begin
construction in 2019 and is expected to begin operating in 2022. These issues, however are
completely germane to DTE Electric’s March 2019 IRP under MCL 460.6t.
As discussed in this order, the Commission provides guidance on how these issues must be
addressed in DTE Electric’s 2019 IRP filing, and further guidance for DTE Electric to consider as
it pursues near and long-term options for meeting energy and capacity needs in a reliable,

6

The Commission recognizes that prior to the 2016 amendment of Section 6s, Section
6s(4)(a) read “approved integrated resource plan that complies with subsection (11).”
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 affordable, and environmentally protective manner while adapting to changing market and
technology conditions.
Although MEC/NRDC/SC are correct that Section 6t(8) contains detailed findings with
respect to the IRP, the Commission disagrees that it should use these criteria for evaluating the
IRP submitted under Section 6s. Had the Legislature intended that the Commission make such
findings, it could have included them in the amendments to Section 6s under Act 341, but the
Legislature did not do so. Finally, the Commission notes that in past proceedings under Section
6s, the extent of the Commission’s “approval” of the IRP was to evaluate whether the application
comported with the CON filing requirements and IRP guidance in effect at the time the application
was filed. See, October 25, 2017 order in Case No. U-18244.
III. APPLICATION

As noted above, on July 31, 2017, DTE Electric filed an application, with supporting
testimony and exhibits, requesting CONs for the construction of a 1,100 MW NGCC electric
generation facility at the company’s Belle River Power Plant site. Specifically, DTE Electric
seeks CONs that: (1) the power to be supplied by the proposed project is needed; (2) the size, fuel
type, and other design characteristics of the proposed project represent the most reasonable and
prudent means of meeting that power need; and (3) the estimated $989 million capital costs of, and
the financing plan for, the proposed project will be recoverable in rates from DTE Electric’s
customers. DTE Electric averred that its application and supporting exhibits meet the CON and
IRP filing requirements of MCL 460.6s and the May 11 order.
Pursuant to the CON filing requirements, prior to submitting an application, the company must
make a filing announcement and engage in a pre-application consultation process. DTE Electric

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 complied with both requirements and no party raised an issue with the company’s actions. In
addition to the filing announcement and pre-consultation process, in light of the CONs DTE
Electric was requesting, the company was required to comply with Sections I, III, IV, V, VI,
VII.A, and VIII.A of the CON filing requirements.
DTE Electric’s compliance with the applicable filing requirements is discussed below.
A. Certificate of Necessity Type
Pursuant to Section V of the Filing Requirements, DTE Electric must identify the relief
requested. The utility may seek one or more of the certificates set forth in Section 6s(3). On page
1 of its application, DTE Electric stated that it is requesting CONs pursuant to Section 6s(3) of
Act 341, and specifically requests the Commission issue:
(i) A certificate of necessity that the power to be supplied by the Proposed Project is needed;
(ii) A certificate of necessity that the size, fuel type, and other design characteristics of the
Proposed Project represent the most reasonable and prudent means of meeting that power need;
and
(iii) A certificate of necessity that the estimated capital costs of and the financing plan for the
Proposed Project including, but not limited to, the costs of siting and licensing the Proposed
Project and the estimated cost of power from the Proposed Project will be recoverable in rates
from the Company’s customers.
These certificates requested, comport with Section 6s(3)(a), (b), and (d) of Section 6s.

B. Certificate of Necessity That the Power to Be Supplied as a Result of the Proposed
Construction, Investment, or Purchase Is Needed
Section VI of the Filing Requirements states that the utility shall identify the projected
resource requirements, the expected timing of the requirements, along with an IRP that identifies
the proposed course of action. The applicant shall either have an approved IRP under Section 6t of
Act 341, or file, as part of their application, an IRP that is consistent with Section 6s(11). DTE
Electric filed an IRP pursuant to Section 6s(11). Exhibit A-4 (2nd Revised). The Commission
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 discusses issues related to load forecasts, coal plant retirements, and the need for power in more
detail in this order.
C. Certificate of Necessity That the Design Characteristics of a Proposed Electric Generation
Facility or Investment in an Existing Electric Generation Facility or the Terms of a Power
Purchase Agreement Represent the Most Reasonable and Prudent Means of Meeting Future Power
Needs
Section VII of the Filing Requirements lists 19 items the utility shall include in the CON
application, if applicable. In this case, the applicable items are as follows:
1. A written description of the proposed or existing site, including identification of the
municipality in which the facility will be constructed and the current use of that site
In the testimony submitted with DTE Electric’s CON application, the company stated the
existing Belle River Power Plant (BLRPP) location was the optimal location for a new gas plant
due to available space within the 1,500 acre property, with access to water and existing
infrastructure including high pressure gas pipelines and high voltage electric transmission lines.
5 Tr 1466-1468, Exhibit A-41.
2. If applicable, the age of the existing facility or facilities to be purchased or modified
DTE Electric’s CON application involves new construction only, and does not include
purchase or modification of an existing facility. Therefore, this item in the Filing Requirements is
not applicable.
3. Expected generating technology and major systems (including major pollution control systems)
DTE Electric stated the proposed project is a nominal 1,100 MW, natural gas combined cycle
plant, with advanced class technology, and best available control technology (BACT) for air
emissions including selective catalytic reduction (SCR) and oxidation catalysts. 5 Tr 1470.
4. Expected nameplate capacity, availability, heat rates, expected life, and other significant
operational characteristics

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 According to DTE Electric, the proposed facility is expected to have a nameplate capacity of
approximately 1,100 MW, and with regular maintenance, is expected to have a 30-year useful life.
The plant heat rate is expected to be below 6,300 British thermal units (Btu) per kilowatt-hour
(kWh) and would represent the most efficient plant in the company’s generation fleet, with an
availability estimated to be greater than 87%. Once operating, the plant also has the capability to
ramp up or down 100 MW per minute. 5 Tr 1471-1472. Additional information on the proposed
plant’s characteristics is discussed in subsection 7, below.
5. Fuel type and sources, including the identification and justification of fuel price forecasts used
over the study period
In testimony included with DTE Electric’s application, the company stated that the proposed
facility could be fueled by natural gas delivered by a variety of nearby large diameter pipelines
including Vector, DTE Gas Company, and Great Lakes Gas Transmission (GLGT). These
pipelines provide gas sourced from multiple regions in the US from traditional supply in the Gulf,
Mid-Continent and Canada, to the shale gas producing regions in the east. DTE Electric explained
that fuel supply will be secured by entering into a firm gas transportation contract to ensure
reliable supply and reduce price volatility. 8 Tr 2553-2555.
6. The expected annual emissions of carbon dioxide and greenhouse gases, particulates, sulfur
dioxides, volatile organic compounds, oxides of nitrogen, mercury, and other hazardous air
pollutants over the life of the facility or contract, and an assessment of whether some or all of the
anticipated emissions and their anticipated health impacts could be eliminated or reduced through
the use of feasible and prudent alternatives
DTE Electric provided testimony and an exhibit addressing this filing requirement. 5 Tr 14441445, Exhibit A-36 revised.
7. Discussion of the rationale behind facility or investment technology, fuel, capacity, and other
significant design characteristics

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 DTE Electric commissioned HDR Engineering, Inc., (HDR) to review alternative power
generation which included various energy options and plant sizes, such as natural gas fueled
simple and combined cycle generation, coal-based generation with carbon capture and
sequestration technology (CCS) renewable energy including biomass, wind and solar, energy
storage options, nuclear energy and market purchases. 5 Tr 1461-1462.
The company screened these options based upon a levelized cost of electricity (LCOE),
eliminating the highest cost options first and further eliminating options based upon a benefit cost
analysis. The remaining resources were then modeled in the IRP including: natural gas CT and
CC, renewable (wind and solar), demand response, storage, energy efficiency (EE or energy waste
reduction (EWR)) and short-term market purchases up to 300 MWs. 6 Tr 1610-1611. As a result
of this analysis, DTE Electric selected the proposed project.
The proposed project is an advanced-class generation technology, multi-shaft 2x1 combustion
turbine combined cycle power plant burning natural gas fuel. 5 Tr 1470-1471. The project will
consist of two combustion turbine generators and heat recovery steam generators equipped with
natural gas duct burners located outdoors, which allows the use of duct firing, increasing the plant
output with minimal impacts on heat rate or emissions. Exhibit A-38, Table 2-12. A steam turbine
generator and some of the balance of plant equipment will be located indoors. The plant will also
include best available control technology (BACT) for air emissions, including selective catalytic
reduction and oxidation catalysts. 5 Tr 1470-1471.
The plant can be operated in a base load mode, an intermediate load follow mode, or at its
lowest turndown mode with one CT generator off and the other CT generator operating at its
minimum emission compliance limit, with generation output of about 25% of its total rated
capacity. 5 Tr 1472.

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 The company’s proposed facility and location has access to sufficient water, natural gas and
electric transmission infrastructure and can be located on existing property adjacent to another
electric generation plant. 8 Tr 2554-2555.
8. A description of all major state, federal, and local permits required to construct and operate the
proposed generation facility or the proposed facility upgrades in compliance with state and federal
environmental standards, laws, and rules
DTE Electric stated that it would obtain all required major construction and operation permits
and permissions, including all permits required by federal, state and local units of government.
5 Tr 1469-1470, 1436-1441.
9. If applicable, the status of any transmission interconnection study and identification of any
expected or required transmission system modifications
DTE Electric stated that it submitted its interconnection request to MISO on June 1, 2017.
7 Tr 2163. While the interconnection studies were not completed, DTE Electric provides an
estimate of transmission upgrade costs.
10. If applicable, natural gas infrastructure required for plant construction and operation not
located on the proposed site but required for plant construction and operation
As discussed in detail above, DTE Electric described the natural gas infrastructure required to
construct and operate the proposed generation facility. 8 Tr 2553-2555.
11. If applicable, a description of modifications to existing road, rail, or waterway transportation
facilities not located on the proposed site but required for plant construction and operation
According to Mr. Damon, “[t]he site also has easy access to rail, road, and international
waterways; thereby alleviating transportation logistics issues.” The company identified no
modifications to existing rail, road or waterway transportation for the proposed project. 5 Tr 1467.
12. If applicable, water and sewer infrastructure required for construction and operation not
located on the proposed site but required for plant construction and operation

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 DTE Electric stated that the Company has not identified a need for any additional
infrastructure required for construction or operation outside the site boundaries. 5 Tr 1475.
13. A basic schedule for development and construction, which include an estimated time between
the start of construction and commercial operation of the facility or facility upgrades
DTE Electric provided Exhibit A-42 that details the project construction schedule. In this
exhibit, the Company expects detailed engineering to begin in the 3rd quarter of 2018 and
construction to begin in the spring of 2019. The proposed project is expected to commence
commercial operation during the 2nd quarter of 2022. 8 Tr 2605.
14. An estimate of the proportion of the construction workforce that will be composed of residents
of the state of Michigan
DTE Electric stated that the Company estimates 90% of the craft labor will be comprised of
Michigan residents. 8 Tr 2615.
15. Descriptions of the alternatives that could defer, displace, or partially displace the proposed
generation facility or significant investment in an existing facility, that were considered, including
a “no-build” option, and the justification for the choice of the proposed project. Comparative costs
of supply alternatives shall be included. The supply alternatives shall consider energy
optimization, load management, demand response, energy storage and renewable energy
DTE Electric stated that its IRP considered alternatives, such as a “no build” option, the
justification for the choice for the proposed project, comparative costs of supply alternatives, EE,
and renewable energy. Exhibit A-4(2nd Revised), Exhibit A-38.
16. Describe the effect of the proposed project on wholesale market competition
According to DTE Electric, the proposed project is expected to increase market competition
because the 1,100 MW proposed plant is significantly smaller than the 2,100 MW of generation
assets that the Company expects to retire. 7 Tr 2235-2236.
17. Any workpapers used in developing the application, supporting testimony, and any
accompanying integrated resource plan. Such workpapers shall, whenever possible, be provided in
electronic format with formulas intact

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 DTE Electric supplied all workpapers on a compact disk along with its application.
18. Any modeling input or output files used in developing the application, supporting testimony,
and any accompanying integrated resource plan. Such modeling input and output files shall,
whenever possible, be provided in electronic format with formulas intact. The applicant shall also
identify each modeling program used, and provide information for how interested parties can
obtain access to such modeling program
DTE Electric included non-confidential modeling input and output files on a compact disk
along with its application. Additionally, and as previously discussed in this order, the ALJ in this
case granted the discovery motion to compel on September 7, 2017 and subsequent motion to
enforce on October 18, 2017 thereby directing the Company to provide all model input and output
files.
19. Any other information that the applicant considers relevant
DTE provided a risk assessment in its 2017 IRP, Section 12 which is further discussed in
testimony. 6 Tr 1756-1771. The company also commissioned a third party assessment of its
modeling process. 7 Tr 1976-1995.
D. Certificate of Necessity That the Estimated Capital or Purchase Costs of the New or Existing
Electric Generation Facility or the Investment in an Existing Electric Generation Facility Will Be
Recoverable in Rates from the Electric Utility’s Customers
Section VIII of the Filing Requirements states that an application seeking a CON to construct
a new electric generation facility shall provide an estimate of the costs required for the specified
purchase or construction, as well as projected facility operation costs. The cost estimates for the
construction of a new facility shall include four items, if applicable. DTE Electric addressed the
three applicable items as follows:
1. To the Extent Applicable and Available, Engineering, Procurement, and Construction Costs,
Transmission Interconnection Costs, Owner’s Costs, and Project Financing Costs

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 DTE Electric stated the estimated capital cost of the project are as follows:
Engineer Procure Construction Cost
Owner’s Cost
Contingency Cost

$879,000,000
$ 55,000,000
$ 55,000,000

TOTAL

$989,000,000

Transmission upgrades

$ 29,000,000

Gas Distribution upgrades (unknown)
Firm Transportation costs (unknown)
8 Tr 2608-2609, Exhibit A-43.
2. For New Construction, the Application Shall Include the Expected Typical Annual Costs
Associated With Operating the Facility, Including Fuel, Operations and Maintenance, and
Environmental Compliance
DTE Electric stated the estimated annual operating and maintenance costs for the proposed
facility are as follows:
35 Full-time Employee (internal workforce)
Fixed O&M including long term service agreement (LTSA)
Variable O&M including LTSA
Fuel not included

$11,000,000
$ 2.47/MWh

7 Tr 2311.
3. A disclosure indicating the portion of investment included in the applicant’s request for a
certificate of necessity which was previously included in the applicant’s rate base
DTE Electric stated that approximately “$.4 million of capital expenditures incurred during
2011-2013 are included in approved rate base. All costs 2014-2017, totaling $13.2 million, were
disallowed by the Commission in U-18014.”
In addition, the company reflected approximately $6.5 million of cumulative project costs
through 2016 in Case No. U-18255 and DTE Electric’s recent rate case reflected $26.6 million of
CWIP for projected year January 2017 – October 2018 and requested inclusion in rate base
without an AFUDC offset. 5 Tr 1499.
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 IV. OVERVIEW OF THE RECORD AND POSITIONS OF THE PARTIES

A. Overview of the Testimony
1. DTE Electric
DTE Electric sponsored the direct testimony and exhibits of 16 witnesses. Charles F. Adkins,
a Vice President in the Consulting Practice of ABB Enterprise Software, Inc. (ABB), provided an
independent assessment of DTE Electric’s IRP models and processes, specifically testifying
regarding the models, optimization, modeling scenarios, and sensitivity analyses. His
qualifications and direct testimony are transcribed at 7 Tr 1970-1995. Mr. Adkins sponsored
Exhibits A-12, A-13, and A-14.
Michael E. Banks, Manager, Power Generation Engineering in the Engineering Support
Organization responsible for the New Gas Generation group in DTE Electric’s Fossil Generation
Department, provided IRP assumptions for DTE Electric’s current generation portfolio, including
details on locations, capacity factors, and projected retirement dates. Mr. Banks’ qualifications,
direct testimony, and revised rebuttal testimony are transcribed at 7 Tr 2298-2320. Cross
examination of Mr. Banks can be found at 7 Tr 2321-2327.
Kevin L. Bilyeu, Principal Marketing Specialist of Energy Optimization Strategy for DTE
Electric, provided an overview of the company’s EE programs, including historical performance,
near-term EE forecast, and the EE sensitivity analyses included in DTE Electric’s IRP. Mr. Bilyeu
sponsored Exhibits A-32 and A-33 and rebuttal Exhibits A-69 through A-71. Mr. Bilyeu’s
qualifications, direct testimony, and rebuttal testimony are transcribed at 7 Tr 1996-2056. Crossexamination of Mr. Bilyeu can be found at 7 Tr 2057-2086.
Timothy A. Bloch, a Principal Financial Analyst in DTE Energy Corporate Services LLC’s
Regulatory Affairs organization, testified about renewal of Public Utility Regulatory Policies Act
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 (PURPA) power purchase agreements (PPAs) and new PPAs. Mr. Bloch’s rebuttal testimony is
transcribed at 8 Tr 2342-2352.
Kevin J. Chreston, DTE Electric’s Manager, IRP and Modeling, testified regarding DTE
Electric’s modeling, analysis, and results for its IRP. Mr. Chreston sponsored Exhibits A-4 (2nd
Revised) through A-10 (3rd Revised), and A-11. Mr. Chreston’s qualifications, direct and rebuttal
testimony are transcribed at 6 Tr 1706-1839. Cross-examination of Mr. Chreston is at 6 Tr 18401955.
William H. Damon III, a Senior Vice President and Director for HDR’s Strategic Consulting
Practice, testified regarding the natural gas generation technologies considered by DTE Electric,
and he described the process the company used in its siting analysis. Mr. Damon also provided
information on the technical specifications of the proposed NGCC plant. Mr. Damon’s
qualifications and direct testimony are transcribed at 5 Tr 1456-1476.
Phillip W. Dennis, Manager, Regulatory Economics for DTE Electric testified on the expected
impact of the proposed project on customer rates. Mr. Dennis’s qualifications and direct testimony
can be found at 8 Tr 2589-2593.
Irene M. Dimitry, DTE Electric’s Vice President of Business Planning & Development,
provided an overview of the company’s CON requests, the IRP, and costs associated with the
project. Ms. Dimitry’s qualifications and direct testimony are transcribed at 6 Tr 1589-1623.
Dan O. Fahrer, DTE Electric’s Director of Major Enterprise Projects Platforms, testified
regarding the costs of the proposed NGCC plant along with the construction schedule and
workforce composition. Mr. Fahrer’s qualifications and direct testimony can be found at 8 Tr
2601-2616.

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 Derek D. Kirchner, Supervisor –Demand Side Management, Business Planning &
Development for DTE Electric, discussed DTE Electric’s demand response (DR) programs
including interruptible air conditioning (IAC), planned pilot DR programs, DR assumptions used
in the IRP models, and the company’s experience with distributed generation (DG) programs.
Mr. Kirchner’s qualifications and direct and rebuttal testimony are transcribed at 7 Tr 2091-2113.
Cross-examination of Mr. Kirchner can be found at 7 Tr 2114-2149.
Markus B. Leuker, DTE Electric’s Manager of Corporate Energy Forecasting, testified
concerning the company’s projected sales, demand, and output forecasts for 2016-2040.
Mr. Leuker’s qualifications and direct testimony are found at 8 Tr 2400-2420.
Barry J. Marietta, DTE Electric’s Supervisor of the Emissions Quality Group, Environmental
Management & Resources, provided information on environmental compliance for the company’s
current generating fleet and for the proposed project. Mr. Marietta’s qualifications and direct and
rebuttal testimony are transcribed at 5 Tr 1431-1452.
Terri L. Schroeder, DTE Electric’s Manager of Business Development in Renewable Energy,
testified concerning DTE Electric’s current renewable portfolio and updates based on 2016 PA
342 (Act 342) requirements. Ms. Schroeder’s qualifications and direct testimony can be found at 8
Tr 2463-2476.
Don M. Stanczak, Vice President, Regulatory Affairs for DTE Electric, provided rebuttal
testimony on DTE Electric’s pending depreciation case and the effects of the Tax Cuts and Jobs
Act (TCJA) of 2017 on the company’s IRP. Mr. Stanczak’s rebuttal testimony is transcribed at
5 Tr 1485-1492.
David Swiech, Manager, Planning and Procurement in DTE Electric’s Fuel Supply
Department, testified concerning DTE Electric’s current fuel procurement practices and provided

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 forecasted fuel price assumptions for the IRP. Mr. Swiech’s qualifications and direct testimony
are transcribed at 8 Tr 2541-2556.
Theresa M. Uzenski, Manager of Regulatory Accounting for DTE Electric and DTE Gas
Company, testified concerning the company’s proposed rate making and accounting treatment of
financing cost recovery for the proposed plant. Ms. Uzenski’s qualifications and direct testimony
are transcribed at 5 Tr 1494-1499.
Edward P. Weber, Senior Technical Advisor and Project Manager in HDR’s System
Protection and Studies Section, discussed transmission issues including how the company acquires
transmission service and the process used by the Midcontinent Independent System Operator Inc.
(MISO) to evaluate and approve transmission projects. Mr. Weber sponsored Exhibits A-34 and
A-35. Mr. Weber’s qualifications and direct and rebuttal testimony are transcribed at 7 Tr 21542174. Cross-examination of Mr. Weber can be found at 7 Tr 2175-2215.
Angela P. Wojtowicz, Director of DTE Electric’s Generation Optimization Department,
provided an overview of the company’s application, including a discussion of MISO resource
adequacy requirements and the company’s current capacity portfolio. Ms. Wojtowicz sponsored
Exhibits A-24 through A-27, and rebuttal Exhibits A-50 through A-63. Her qualifications, revised
direct testimony and revised rebuttal testimony can be found at 7 Tr 2221-2255. Crossexamination of Ms. Wojtowicz is transcribed at 7 Tr 2256-2293.
2. Commission Staff
The Staff presented testimony of seven witnesses. Karen M. Gould, an Auditor in the Energy
Waste Reduction Section of the Commission’s Electric Reliability Division, testified regarding the
Staff’s recommendations for EE implementation in DTE Electric’s CON proceeding. Ms. Gould
sponsored Exhibits S-3.1 through S-3.3. Ms. Gould’s testimony is transcribed at 5 Tr 238-253.

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 Jesse J. Harlow, a Public Utilities Engineer in the Renewable Energy Section of the
Commission’s Electric Reliability Division, testified about DG modeling scenarios that the
company did not include in its presentation. Mr. Harlow sponsored Exhibit S-5.1 and his
testimony can be found at 5 Tr 262-270.
Olumide O. Makinde, an Economic Analyst in the Resource Adequacy and Retail Choice
section of the Commission’s Financial Analysis and Audit Division, testified regarding the Staff’s
review of DTE Electric’s load and natural gas price forecasts and an assessment of the company’s
IRP planning methods and models. Mr. Makinde sponsored Exhibit S-2.1 through S-2.7.
Mr. Makinde’s testimony is transcribed at 5 Tr 218-237.
Robert F. Nichols II, Manager of the Revenue Requirements Section of the Commission’s
Financial Analysis and Audit Division, testified about the company’s request for current recovery
of financing costs of the proposed project. Mr. Nichols’ testimony is transcribed at 6 Tr 15751580. Cross-examination of Mr. Nichols can be found at 6 Tr 1581-1585.
Paul A. Proudfoot, Director of the Commission’s Electric Reliability Division, provided an
overview of the Staff’s position on DTE Electric’s application. Mr. Proudfoot’s testimony is
transcribed at 5 Tr 173-187.
Naomi J. Simpson, a Public Utilities Engineer in the Generation and Certificate of Need
Section of the Commission’s Electric Reliability Division, testified regarding DTE Electric’s
compliance with the requirements of MCL 460.6s. Ms. Simpson sponsored Exhibit S-1.1 through
Exhibit S-1.11. Ms. Simpson’s second corrected direct testimony can be found at 5 Tr 188-217.
Katie J. Smith, an Economic Analyst in the energy waste reduction (EWR) Section of the
Commission’s Electric Reliability Division, provided the Staff’s recommendations regarding DR

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 resources and programs. Ms. Smith sponsored Exhibits S-4.1 through S-4.3. Ms. Smith’s
testimony is available at 5 Tr 254-261.
3. Attorney General
The Attorney General sponsored the testimony of Philip DiDomenico, Managing Consultant
at Daymark Energy Advisors. Mr. DiDomenico reviewed DTE Electric’s application, testimony,
and exhibits and provided recommendations for future IRP proceedings. He sponsored Exhibits
AG-1 through AG-20. Mr. DiDomenico’s testimony is transcribed at 6 Tr 1519-1571.
4. Association of Businesses Advocating Tariff Equity
ABATE sponsored the direct and rebuttal testimony of Nicholas L. Phillips, an Associate with
Brubaker & Associates. Mr. Phillips provided an analysis and recommendations with respect to
DTE Electric’s request for CONs for an NGCC. Mr. Philips’ testimony and rebuttal testimony are
transcribed at 5 Tr 273-311.
5. Environmental Law and Policy Center et.al.
ELPC, et al., sponsored the testimony of Kevin Lucas, Director of Rate Design at the Solar
Energy Industries Association. Mr. Lucas provided an overview of solar energy issues relevant to
this proceeding and provided a review of DTE Electric’s IRP modeling and risk assessment. He
sponsored Exhibits ELP-1 through ELP-56, and his qualifications and direct testimony are
transcribed at 5 Tr 654-874.
R. Thomas Beach, principal consultant of the consulting firm Crossborder Energy, presented
recommendations concerning DTE Electric’s request for a CON for a new gas plant. Mr. Beach
sponsored Exhibits ELP-58 through ELP-62. His corrected direct testimony and rebuttal
testimony are transcribed at 5 Tr 896-994.

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 Michael B. Jacobs, Senior Energy Analyst for the Union of Concerned Scientists, testified
regarding the manner in which DTE Electric addressed energy storage in the company’s IRP.
Mr. Jacobs’ qualifications and direct testimony are transcribed at 5 Tr 875-895.
Phillip Jordan, a principal with BW Research Partnership, provided an economic impact
analysis of jobs in the renewable energy and EE sectors. He sponsored ELP-63 and his testimony
is transcribed at 5 Tr 995-998.
6. Michigan Environmental Council, Natural Resources Defense Council, and Sierra Club
MEC sponsored the testimony of Josh Berkow, Principal Power Systems Engineering
Consultant for RINA Consulting, who testified regarding transmission options for DTE Electric.
Mr. Berkow sponsored Exhibits MEC-88 and MEC-89, and his testimony is transcribed at 5 Tr
544-550.
MEC/NRDC/SC sponsored the testimony of five witnesses. Avi Allison, an Associate with
Synapse Energy Economics, reviewed the renewable resource and capacity price modeling
assumptions in DTE Electric’s IRP, as well as the company’s risk analysis. Mr. Allison sponsored
Exhibits MEC-49 through MEC-71 and his testimony is transcribed at 5 Tr 444-499.
Robert Fagan, Principal Associate at Synapse Energy Economics, provided an evaluation of
DTE Electric’s modeling for its IRP. Mr. Fagan sponsored Exhibits MEC-90 through MEC-108,
and his testimony is available at 5 Tr 551-590.
Chris Neme, Principal of Energy Futures Group, a consulting firm specializing in and
renewable EE energy, testified regarding the EE assumptions included in DTE Electric’s IRP.
Mr. Neme sponsored Exhibits MEC-17 through MEC-39. Mr. Neme’s testimony is transcribed at
5 Tr 357-410.

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 Dale Osborn, a consulting electrical engineer with specialization in transmission planning,
testified concerning transmission options, resource adequacy, import limits, and DTE Electric’s
request for proposals (RFP) for generating assets. Mr. Osborn sponsored Exhibits MEC-72
through MEC-87, and his testimony can be found at 5 Tr 500-543.
George W. Evans, President of Evans Power Consulting, Inc., testified regarding DTE
Electric’s Strategist modeling analyses and presented the results of the modeling that he
performed. Mr. Evans sponsored Exhibits MEC-1 through MEC-6, and MEC-9, MEC-10, and
MEC-12 as well as confidential Exhibits MEC-7C, MEC-8C, MEC-11C, and MEC-13C through
MEC 16C. Mr. Evans’ direct, rebuttal, and supplemental testimony is transcribed at 5 Tr 316-356.
7. Michigan Cogeneration Venture Limited
Kevin R. Olling, Vice President of Energy Supply and Marketing for MCV testified regarding
DTE Electric’s competitive bid process related to market-based alternatives to the company’s
proposed project. Mr. Olling sponsored Exhibits MCV-1 and MCV-2. His testimony is
transcribed at 5 Tr 607-623.
8. Michigan Energy Innovation Business Council
EIBC sponsored the testimony of Hannah Hunt, a Senior Analyst, Industry Data & Analysis,
at the American Wind Energy Association. Ms. Hunt provided cost and performance updates for
wind energy and made recommendations concerning DTE Electric’s IRP. Ms. Hunt’s testimony is
transcribed at 5 Tr 627-650.
MEC/NRDC/SC and EIBC sponsored separate parts of the testimony of Douglas B. Jester, a
Partner of 5 Lakes Energy LLC. Mr. Jester testified regarding DR, PURPA resources, and
customer-requested renewable energy under MCL 460.1061. Mr. Jester sponsored Exhibits MEC40 through MEC-48, and his testimony is transcribed at 5 Tr 411-443.

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 B. Positions of the Parties
1. DTE Electric
DTE Electric contends that it met all of the filing requirements that were in place at the time
the company submitted its application for the CONs. Further, DTE Electric maintains that the
preponderance of the evidence demonstrates that the power to be supplied by its proposed project
is needed due to the retirement of eight coal-fired units 7 scheduled for 2020-2023. The retirement
of these units was necessitated by age, the cost of compliance with environmental regulations, and
the company’s goal to reduce carbon emissions from its generation fleet. DTE Electric points to
its analysis that shows that retirement of the units is more economical than further investment;
however, the power lost from these units will need to be replaced in order to meet MISO reliability
requirements. DTE Electric observes that only ABATE disagrees that the units should be retired.
Next, DTE Electric argues that given the import limits for capacity, the company cannot
obtain sufficient power outside of local resource zone (LRZ or Zone) 7 and firm capacity
purchases from outside Zone 7 do not address the local clearing requirement (LCR) inside the
zone. According to DTE Electric, the company’s IRP indicates a need for 472 MW of additional
capacity in 2022, increasing to 1,266 MW in 2023 after the remaining Tier 2 units are retired.
DTE Electric noted that, because it must demonstrate that it meets its capacity requirements four
years into the future under MCL 460.6w, it cannot rely on the MISO planning reserve auction
(PRA) capacity prices to model capacity cost and that the company correctly used a bilateral
capacity purchase forecast in its modeling. DTE Electric pointed out that the Commission has

The units to be retired are River Rouge Unit 3, St. Clair Units 1-3 and Units 6-7, and Trenton
Channel Unit 9 (Tier 2 units). St. Clair Unit 4 was retired while this case was pending.
7

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 expressed concerns about system reliability in the wake of aging generation plants and planned
and unplanned retirements.
DTE Electric contends that its proposed project is the most reasonable and prudent means to
meet the power deficit, claiming that no other party proposed a specific, alternative project. DTE
Electric argues that its IRP modeled several load forecasts and considered both supply-side and
demand-side resources in developing a plan that calls for 1.5% energy efficiency savings, 15%
renewable energy by 2021, 125 MW of additional demand response (DR), and one 1,100 MW
NGCC plant in 2022 and second 1,100 MW plant in 2029. DTE Electric highlighted the steps it
undertook in developing various modeling scenarios, as well as the sensitivity analyses that it ran.
In addition, DTE Electric updated its assumptions in 2017 (2017 Reference Case) to address the
effects of new energy legislation and more recent market prices, load forecasts, and fuel prices.
The company claims that its modeling resulted in the most reasonable and prudent solution to
address the company’s long-term load requirements.
DTE Electric maintains because of MISO planning requirements, import constraints, and the
paramount need for reliability, transmission alternatives are of limited use in replacing the
proposed project, observing, “it is imperative to have reliable capacity within LRZ 7 to, at a
minimum, meet the LCR. Accordingly, as capacity resources in LRZ 7 retire (like the River
Rouge, St. Clair and Trenton Channel plants are planned to do, removing ~ 1,822 MW
of capacity), new capacity resources need to be built in LRZ 7.” DTE Electric’s initial brief, p. 24.
DTE Electric further argued that “[e]ven if transmission import limits could be expanded in a
timely manner, the Company would be taking considerable risk if it simply assumed that there
would be available capacity at reasonable cost in neighboring MISO zones.” Id. p. 59.

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 DTE Electric undertook a siting study and highlighted the advantages of the selected location
(adjacent to the Belle River Power Plant) including access to significant natural gas infrastructure.
DTE Electric issued requests for proposals (RFPs) for engineering, procurement, and construction
(EPC) and power island equipment (PIE) for the proposed project. To the costs from the
successful bid, DTE Electric added a 6% contingency consistent with acceptable construction
practices. The company also issued an RFP to determine if there were market-based options that
would be more economical than the proposed plant. DTE Electric contends that its RFP and
conforming bid requirements were reasonable, consistent with resource constraints, and
recognized the significant risks inherent in relying on a long-term PPA. As a result, the company
did not receive any conforming bids that were more cost-effective than the proposed project.
With respect to its IRP submitted in support of its proposed project, DTE Electric argues that
the forecasts it used for load, fuel prices, and wind and solar resource costs were based on reliable
forecasting methods (load, fuel cost) or on the company’s historical costs (wind and solar). DTE
Electric disputed that customer-requested renewable energy under MCL 460.1061 will be a
significant driver of additional renewables over the life of the IRP. The company added that it
appropriately evaluated alternative resource options, including no build, additional renewable
energy, EE, and DR, that could defer, displace, or partially displace the proposed project. DTE
Electric asserts that “even the most aggressive EE and DR alternatives would still leave a
substantial shortfall[,]” adding that “[a]cross all of the cases modeled, the modeling tool never
selected additional renewables beyond the minimum statutory target of 15%.” DTE Electric’s
initial brief, pp. 46-47. For EE, the company pointed out that the IRP includes 1.5% savings,
which is above the statutory mandate of 1%, and that the DR savings included in the plan are
consistent with achievable DR potential, pointing out that the recommendations for additional EE

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 and DR, made by other parties, are overly optimistic or otherwise inappropriate. DTE Electric
also dismissed generation available from qualifying facilities (QFs) under PURPA, noting that
there are concerns about the viability of some existing PURPA QFs as well as questions about
changes to the law. DTE Electric also questioned the reliability of renewable energy compared to
the proposed project, which has significant capability to meet customers’ needs for varying
amounts of power.
Finally, DTE Electric argued that its risk analysis, and an independent review, confirmed that
the proposed NGCC plant was the most reasonable and prudent means to meet the company’s
future power needs. In addition, DTE Electric averred that the project will comply with all
environmental requirements and will provide benefits to local communities and the state.
Accordingly, DTE Electric concluded that the Commission should grant the requested CONs and
find that the capital and financing costs of the project are recoverable in rates.
2. Commission Staff
The Staff recommends that the Commission approve DTE Electric’s requests for CONs under
Section 6s(3)(a), (b), and (d) noting, however, that there are sufficient deficiencies in the
company’s analysis that the Commission could decide otherwise and might direct the company to
refile its application, or it might approve a smaller plant. The Staff recommends that in the
company’s March 2019 IRP filing under MCL 460.6t, the Commission should require DTE
Electric to file a stronger case that complies with the updated filing requirements. In addition, in
order to avoid the need to build additional capacity in the long term, the Staff recommends that the
company be required to base its DR and EE levels on the more rigorous statewide potential
studies, rather than on the company’s potential studies.

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 3. Attorney General
The Attorney General urges the Commission to carefully review DTE Electric’s CON
requests, and proceed with caution in light of the cost that will be borne by customers in future rate
case proceedings. The Attorney General claims that although the company has adequately shown
a need for the power in this case, in future IRPs, DTE Electric should be required to undertake a
more robust and transparent analysis. The Attorney General further suggested that in the future,
the Commission should demand a better evaluation of the potential for capacity to be supplied
from resources outside of MISO LRZ 7, noting his concerns about DTE Electric’s refusal to
consider resources outside of Zone 7, despite available import capacity.
The Attorney General also supported DTE Electric’s request for a CON finding that the
proposed plant is the most reasonable and prudent means of supplying the power, notwithstanding
deficiencies in the company’s IRP and a lack of transparency in the modeling process. The
Attorney General expressed reservations about DTE Electric’s RFP process for alternatives to a
new build, but he nevertheless noted that no alternative proposals were presented in the
proceeding. Finally, the Attorney General opposed DTE Electric’s request to include contingency
costs as part of its project, contending that the plain language of Section 6s precludes the approval
of such costs in a CON.
4. Association of Businesses Advocating Tariff Equity
ABATE contends that DTE Electric provided incomplete, inaccurate, and contradictory
analyses in support of its application, and therefore the Commission should deny the requested
CONs. Specifically, ABATE argues that due to the passage of the TCJA in late 2017, DTE
Electric’s Tier 2 unit retirement analysis, IRP, and forecasted costs for the proposed NGCC plant
are now incorrect. ABATE points out that both Mr. Chreston and Mr. Nichols admitted that the

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 tax-related inputs to the various models did not reflect the material changes brought about by the
TCJA.
ABATE further posits that, given expected changes to federal environmental regulations under
the current federal administration, the assumptions about additional pollution controls required for
the company’s coal fleet are now unreliable. ABATE also argues that because DTE Electric’s
retirement analysis for the Tier 2 units used a different model, and different inputs from those used
in the company’s IRP and CON analyses, the cost of early retirement versus new build cannot be
appropriately compared. ABATE further contends that many of the cost inputs to DTE Electric’s
various models were from 2016 and should be updated in a new IRP.
5. Michigan Environmental Council, Natural Resources Defense Council, and Sierra Club
MEC/NRDC/SC point out that DTE Electric’s proposal must not only comply with MCL
460.6s and the Commission’s filing requirements as established by the May 11 order, but the
Commission must also ensure that the proposal complies with the Michigan Environmental
Protection Act (MEPA) MCL 324.1701 et seq. even though Section 6s does not expressly mention
MEPA.
According to MEC/NRDC/SC, the Commission should reject DTE Electric’s CON because
the company’s analyses were deficient and inconsistent. MEC/NRDC/SC points to the filing
requirements that state that the IRP shall propose a “course of action,” maintaining that the course
DTE Electric plans to follow is in fact a step backward and is inconsistent with the company’s
own evidence in this case.
MEC/NRDC/SC also criticize DTE Electric’s failure to incorporate additional amounts of
renewable energy, EE, and DR in its projections, claiming that DTE Electric used incorrect or

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 unsupported assumptions, limited the size options that the model could pick for these resources,
and restricted the timing to implement these resources until 2022.
MEC/NRDC/SC also question DTE Electric’s analysis of transmission options, arguing that:
(1) the company’s analysis of current transmission capability is substantially out-of-date; (2) the
company failed to analyze capacity import at all; (3) DTE Electric’s refusal to consider resources
outside of Zone 7 in its RFP was unjustified; and (4) the company’s assumed restriction of imports
to 300 MW of spot purchases in its modeling was unreasonable. MEC/NRDC/SC further posit
that DTE Electric’s transmission analysis did not comply with the requirements of MCL
460.6s(11)(f) or the IRP filing requirements under Exhibit B to the December 23 order.
Next, MEC/NRDC/SC contend that, “DTE’s IRP compares optimal to non-optimal resource
plans, resulting in misleading information and non-transparent decision-making.” Specifically,
MEC/NRDC/SC argue, “the record shows that DTE rejected the optimal resource plan in the leastcost sensitivity– the 2% Energy Efficiency case – on the basis it would delay its proposed NGCC
and add demand response resources. DTE instead selected a less-optimal and more-costly 1.5%
Energy Efficiency case for its proposed course of action.” MEC/NRDC/SC’s initial brief, p. 76.
MEC/NRDC/SC point out that Strategist produces a number of possible outcomes for each given
scenario and ranks them in order of cost from lowest to highest. MEC/NRDC/SC acknowledge
that there are often good reasons not to pick the optimal plan selected by the program, but DTE
Electric failed to identify which plan was the optimal plan in each of its Strategist runs, and failed
to support its selection when it chose a plan with a lower ranking.
Next, MEC/NRDC/SC criticize DTE Electric’s 2017 Reference Case, noting that the company
erroneously used a much lower heat rate for the NGCC in its update, thereby making the plant
appear more economical than it is. Although the company claimed to have addressed the error,

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 and that it did not change the results of the analysis in any event, MEC/NRDC/SC maintain that it
“further undermine[s] the accuracy and integrity of the IRP modeling and analysis.”
MEC/NRDC/SC’s initial brief, p. 83.
MEC/NRDC/SC contend that DTE Electric’s rate impact analysis, required under the
December 23 order, was misleading. MEC/NRDC/SC state that DTE Electric opted to base its
analysis on a comparison between a no-build option, which would rely on costly market purchases
of capacity and energy and the capital and operating cost of the proposed NGCC plant.
MEC/NRDC/SC claim that this comparison is deceptive and unreasonable because the rate impact
analysis in the filing requirements does not call for a comparison, DTE Electric described the nobuild option as infeasible, and there were several other viable options presented on which to base a
comparison.
Finally, MEC/NRDC/SC argue that an additional reason for the Commission to deny the
requested CONs is the fact that the company’s own modeling shows that increasing energy
efficiency to 2% in the near term would delay the plant until 2023 or later, sufficient time for DTE
Electric to submit a more robust and transparent IRP under MCL 460.6t. In addition,
MEC/NRDC/SC contend that the option to delay the plant until 2023 is more economical than
DTE Electric’s preferred plan, and other parties presented reasonable and prudent plans that would
delay the plant even further, to 2026 or 2030, resulting in significant savings to customers.
6. Environmental Law and Policy Center et al.
ELPC et al. argue that DTE Electric’s analysis was so fundamentally flawed that the
Commission should deny the requested CONs. ELPC et al. argue that DTE Electric’s failure to
explore reasonable alternatives to its proposed NGCC plant means that the company did not meet
its burden, under Section 6s(4)(d), to show that its proposal is the most reasonable and prudent

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 means to meet its power need. Specifically, ELPC et al., contend that DTE did not accurately
model the availability and cost of solar and wind resources, and significantly understated the
achievable potential for DR and EE. In addition, DTE Electric simply ignored any obligations it
has under PURPA and assumed there would be no additional QF power added to its portfolio.
Citing Federal Energy Regulatory Commission (FERC) Order 841, ELPC et al. also point out that
the company failed to consider adding battery storage, despite how quickly the technology is
developing.
ELPC et al. provided an alternative portfolio, which according to ELPC et al. showed that the
NGCC could be delayed until 2027 and would save ratepayers an estimated $1.2 billion. Finally,
ELPC et al. take issue with DTE Electric’s risk analysis, claiming that the company did not
properly model fuel-price risk or the risk that the proposed NGCC plant could become a stranded
asset as other technologies evolve and become less costly.
7. Michigan Energy Innovation Business Council
EIBC urges the Commission to deny the requested CONs on several grounds. First, EIBC
contends that DTE Electric has failed to demonstrate that the power is needed as required under
MCL 460.6s(4)(a). According to EIBC, DTE Electric’s IRP fails to account for energy and
capacity that the company is required to purchase under PURPA through both new and renewed
contracts, and it fails to include customer-requested renewable energy under MCL 460.1061.
EIBC also contends that DTE Electric’s IRP does not comply with Section 6s(11) because the
company’s analysis includes incorrect information concerning the cost of wind energy. EIBC
further claims that DTE Electric, while using the correct source, used the wrong capacity credit for
wind, resulting in wind as a more costly resource than it actually is. EIBC argues that although
DTE Electric proposes to add additional wind energy to its portfolio, the timing of these additions,

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 during and after the phase-out of the federal Production Tax Credit (PTC), increase the cost of
wind substantially and unnecessarily. Finally, EIBC argues that in failing to make a reasonable
analysis of the alternatives that could potentially displace all or a portion of DTE Electric’s
proposed NGCC plant, the company did not make the requisite showing under MCL 460.6s(4)(d)
that its proposal was the most reasonable and prudent means to supply power.
8. Ann Arbor
Ann Arbor claims that DTE Electric’s assumption, that PURPA contracts with existing QFs
will not be renewed, is unreasonable because it “creates an artificial need for new capacity, and
threatens to displace existing QF capacity with DTE’s own new generating capacity.” Ann
Arbor’s reply brief, p. 2. Ann Arbor points out that the company’s rationale, namely that PURPA
might change or be repealed before contract renewals occur, and therefore power from existing
QFs should be excluded, is groundless because the more realistic assumption is that PURPA will
continue in effect. Ann Arbor further argues that DTE Electric’s other justification for omitting
existing QF capacity from its IRP, namely that the Ann Arbor facilities may not be operating when
their contracts end, is also a baseless assumption. Similarly, Ann Arbor claims that DTE Electric
assumed, unreasonably, that there will be no new PURPA capacity added to the company’s
generation portfolio, despite the must-purchase obligation under PURPA and recent Commission
activity resetting avoided costs. Accordingly, Ann Arbor argues that DTE Electric failed to
demonstrate the full need for capacity to be filled by the proposed project.

V. FINDINGS AND CONCLUSIONS UNDER MCL 460.6s(4)

Although the parties elected, for the most part, to organize their briefing consistent with the
three CONs that DTE Electric requested, the Commission observes that the findings it must make
under Section 6s(4) are more detailed and therefore more suitable for the discussion and analysis
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 in this order. Moreover, while the IRP is mentioned specifically under Section 6s(4)(a), the
Commission notes that the IRP modeling undergirds multiple aspects of the Commission’s
inquiry, thus, except for the portion of the IRP addressing the company’s unit retirement analysis,
the remainder of the IRP is addressed in detail, infra.
Given the abbreviated, 270-day time-frame allowed for this proceeding, coupled with a record
that is more voluminous than usual, not all of the material presented can be discussed in detail.
The various parties’ summaries of the evidence and arguments in support of their respective
positions are fully set forth in their pleadings and briefs, and the basis for the parties’ claims may
be found in the testimony and exhibits. Thus, although the Commission has considered the entire
record in arriving at its findings and conclusions stated below, only those arguments, testimony,
and exhibits necessary for a reasoned analysis of the disputed issues will be specifically addressed
in this order.
A. Has DTE Electric demonstrated a need for the power that would be supplied by the proposed
electric generation facility through its integrated resource plan?
The applicable CON filing requirements and CON IRP guidelines do not articulate how the
“need” for power is demonstrated. As discussed in the load forecasting section below, however,
the CON IRP guidelines require a forecast of economic indicators, electric load forecasting, peak
demand, available generation, fuel costs, and environmental costs. Forecasts should include
among other things, effects of demand-side management, environmental limitations, planning
reserve margin and system reliability requirements, or other legislative or societal developments
that will likely impact future energy requirements.
As noted above, DTE Electric avers that, as a result of its plan to retire eight coal-fired units
between 2020 and 2023, it has demonstrated a need for the proposed NGCC plant in 2022.
Specifically, DTE Electric explained that “the Company will require 472 MW of additional
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 capacity to meet its projected [planning reserve margin requirement] PRMR beginning in 2022 . . .
This shortfall grows to 1,266 MW in 2023 after the announced coal plant retirements are
complete.” DTE Electric’s initial brief, p. 23. ABATE questions whether the units actually
should be retired in light of recent tax law and environmental policy changes.
In its reply brief, p. 19, DTE Electric explains:
In 2014, the [Environmental Protection Agency] EPA finalized regulations on
cooling water intake under section 316(b) of the Clean Water Act (“CWA”). In
2015, the EPA issued its final rule related to water discharge or effluent limitation
guidelines (“ELG”) for steam electric power generators. The updated requirements
in section 316(b) and the ELG impact the future operations of the Company’s coal
generating units (6T 1604), with ELG compliance capital expenditures estimated at
$370 million, and 316(b) compliance costs exceeding $100 million.
DTE Electric added that in addition to stricter and more costly environmental regulations, the
company’s decision to retire the Tier 2 units was driven by the age and operating cost of the units,
as well as the company’s goal, supported by its customers, to move to a lower-carbon generation
portfolio.
Mr. Marietta testified that in addition to ELG and 316(b) regulations, the company’s
generating units are also subject to the National Ambient Air Quality Standards (NAAQS) and the
Coal Combustion Residuals (CCR) Rule. 5 Tr 1436. Mr. Marietta continued, discussing the
regulatory requirements and the impact of the ELG, 316(b), NAAQS, and CCR rules on the
company’s coal generating fleet. 5 Tr 1436-1441. Mr. Marietta testified that DTE Electric took
the Clean Power Plan (CPP) into account in developing its retirement analysis, noting that the CPP
was stayed at the time DTE Electric was analyzing unit retirement. Mr. Marietta also testified that
the company recently announced plans to reduce its carbon emissions by 30% in the early 2020s,
45% by 2030, 75% by 2040, and over 80% by 2050 compared to 2005 carbon emissions. 5 Tr
1446.

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 Mr. Chreston testified that DTE Electric performed an economic analysis on all of the
company’s coal units to evaluate the impact of investing capital to bring each unit into compliance
with the ELG and 316(b) requirements versus early retirement. First, units with similar operating
characteristics were grouped together and then an economic analysis was done to determine the net
present value (NPV) of early retirement (i.e., 2023 or before) as opposed to keeping the units
operating for five years after the compliance date for the ELG regulations (i.e. 2028) 6 Tr 17291730. Mr. Chreston concluded that “[t]he economics from this study indicate that it is better to
retire St. Clair, Trenton 9, and River Rouge before the Environmental Retrofits are required in
2023 and it is better to keep operating Belle River and Monroe and make them compliant to the
ELG and 316(b) regulations.” 6 Tr 1731.
Mr. Chreston presented a chart (Figure 2) demonstrating that the Tier 2 units had an NPV
ranging from negative $31 million to negative $84 million, whereas Belle River and Monroe
showed positive NPVs of $232 million and $2.085 billion respectively. Id. Mr. Chreston also ran
sensitivity analyses on all of the units or unit groups (except Monroe) evaluating higher capital
costs for compliance, low market prices for capacity, and a CO2 sensitivity analysis. Mr. Chreston
presented his results in Figure 3, which demonstrates that except under low market capacity prices,
and except for St. Clair Unit 7 and Trenton Channel, it is more economical to retire the Tier 2
units. Even Trenton Channel and St. Clair Unit 7, show only a modest positive NPV under the
low capacity price scenario. 6 Tr 1732.
Mr. Phillips testified that because DTE Electric’s retirement evaluation was conducted in early
2016, assumptions related to taxes and environmental regulations are no longer correct and must
be updated. 5 Tr 275. Mr. Phillips raised several concerns about the company’s retirement
analysis, including a shift in the approach to environmental and tax policies under the new

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 administration, the need to update modeling inputs to reflect more current demand and commodity
prices, and the fact that the retirement analysis did not reflect increased depreciation expense
resulting from the retirements. With respect to the last point, Mr. Phillips testified that DTE
Electric would be requesting an addition $149 million in depreciation expense related to steam
generation in the company’s next rate case. 5 Tr 279-282.
Mr. Phillips pointed out that DTE Electric’s coal retirement analysis includes CPP
compliance, despite the court-ordered stay, adding that the EPA has stayed compliance with the
ELG pending further review, similar to the situation with the CPP. According to Mr. Phillips, if
the ELG is rescinded or appreciably revised, DTE Electric’s cost estimate for compliance may be
significantly overstated. Even if the rules are not extensively changed, Mr. Phillips claimed that
the substantial change in the corporate tax code due to the TCJA will make environmental
compliance less costly. 5 Tr 285.
Mr. Phillips also took issue with the inconsistency between the modeling programs used for
DTE Electric’s coal retirement analysis (PROMOD) versus its IRP (Strategist). Mr. Phillips
observed that not only did the company use different programs, but it also used different
assumptions for load forecasts and commodity prices between the two analyses. 5 Tr 293.
Mr. Phillips admitted that DTE Electric’s proposal to retire older coal units and replace them
with gas is not unique to Michigan and is in fact occurring nationwide. Nevertheless, Mr. Phillips
contended that because Michigan has limited import capability, more resources will need to be
built in-state. Thus, a decision to retire units before the end of their useful lives has more
significant implications for customer rates in Michigan. 5 Tr 294-295.
Mr. Phillips opined that because the company has not definitively established that the
retirement of the coal units is in the public interest, the Commission should deny DTE Electric’s

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 request for the CONs. Further, Mr. Phillips recommended that the Commission direct DTE
Electric to rerun its coal unit retirement analysis to reflect known changes to federal tax and
environmental policy and update its IRP modeling scenarios to comport with the Commission’s
most recent filing and IRP modeling requirements. 5 Tr 276.
In rebuttal, Mr. Marietta pointed out that although the CPP has been stayed by the U.S.
Supreme Court, the ELG is only targeted for review and possible revision. In the meantime, “the
regulation remains in place with final compliance dates at the end of 2023. The outcome of the
ELG review is not expected to be known until fall of 2020 and any assumptions made by
Witness Phillips are purely speculative.” 5 Tr 1451. Similarly, Mr. Chreston pointed out that
although the CPP has been stayed, the rule has not been withdrawn, thus:
It would be imprudent to change the Company’s plans based on speculation. Not
moving forward with the retirement of the Tier 2 units in the early 2020s would put
these units at risk in regards to ELG, and CPP if it becomes effective. Additionally,
the exact requirements for the Company’s plants related to [sulfur dioxide] SO2,
National Ambient Air Quality Standards (NAAQS) are unknown, there is no reason
to believe that retirement dates later than currently planned by DTE Electric for the
Tier 2 plants are feasible based on the environmental regulations at this time.
Waiting for a final determination would limit the amount of time needed to secure
an optimal replacement.
6 Tr 1822.
Mr. Stanczak addressed the depreciation and TCJA issues raised by Mr. Phillips, testifying
that DTE Electric’s depreciation case is still pending, and the company may not be seeking a
$149 million increase in depreciation expense in its next rate case. Mr. Stanczak noted that the
Staff and ABATE have proposed depreciation rates that differ significantly from the company’s
recommended rates. 5 Tr 1490. In addition, Mr. Stanczak stated that the increased depreciation
expense is not exclusively related to coal unit retirement; some portion is related to higher plant
retirement costs. Mr. Stanczak added:

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 [T]he Company uses the Group Method of depreciation and generally does not
track depreciation reserves within each utility account down to the individual plant
level. . . . Consistent with the Group Method, at the time an individual plant retires,
any theoretical undepreciated plant balances will be recovered through the process
of resetting depreciation rates for the remaining plants in the group. Thus,
ABATE’s claim is erroneous because under the Group Method, depreciation rates
are not plant specific, depreciation expense will be recovered over the life of all
similar assets, and the impact to depreciation rates for certain accounts cannot be
made in isolation.
5 Tr 1491.
Mr. Stanczak agreed with Mr. Phillips that the TCJA’s reduction of deferred taxes will have a
significant effect on the company’s revenue requirement in the future; however, he disputed
whether it has any impact in this proceeding, noting that the remeasurement of deferred taxes does
not affect plant that goes into service after January 1, 2018.
Mr. Chreston testified that with respect to the coal retirement analysis, the TCJA affects the
deferred tax liability balance, pre-tax marginal cost of capital, and discount rate. The sum of these
effects is expected to be minimal in the results of the retirement analysis “because all three impacts
are applied to both the base case and the change cases.” Therefore, “[a] revision in the Coal
Retirement Analysis is unwarranted.” 6 Tr 1823.
Responding to ABATE’s concerns about the different analytical tools used for the retirement
analysis and IRP, Mr. Chreston explained that the retirement analysis was undertaken in the initial
phase of project planning, and that the use of PROMOD modeling was appropriate. Mr. Chreston
added that “[a]ny further optimization using Strategist was proved to be highly unlikely through
the IRP process, and would have made the case for retirement even stronger.” 6 Tr 1825.
Mr. Beach also responded to ABATE’s claims, opining that the TCJA would have a lesser
impact on resource planning cases than on revenue requirements set in a rate case. In this IRP,
Mr. Beach maintained that all resource options would be affected more or less equally by the new

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 tax rates. Mr. Beach further testified that even if the ELG costs are removed from DTE Electric’s
analysis, the NPV of early retirement of the units is still positive. 5 Tr 984, note 8. Mr. Beach
also points out that many industrial customers, some of whom are ABATE members, are seeking
more renewable energy and are not advocating that older coal units remain in operation. 5 Tr 987988.
Mr. Fagan similarly testified that DTE Electric’s latest modeling demonstrates that even if the
CPP and ELG were rescinded, continued operation of the Tier 2 units remains uneconomical. In
response to Mr. Phillips’ suggestion that updated load and commodity forecasts would affect the
retirement analysis, Mr. Fagan agreed, but indicated that the projected decrease in demand and
lower capacity and energy price forecasts compared to 2016 makes the economics of early
retirement of these units even more favorable. 5 Tr 596-599.
The Commission finds that ABATE’s claims should be rejected. 8 First, the Commission
agrees with DTE Electric that ABATE’s assertions about the future status of various federal
environmental policies and regulations are speculative. As the company argues, it would be
unreasonable and potentially much more costly if the company were to assume that either the CPP
or the ELG will be withdrawn or rescinded. And regardless of the EPA’s actions, there would
likely be potentially protracted litigation that would extend well beyond the period in which
decisions would need to be made about the retirement of these plants. Further, as Mr. Fagan
testified:
[U]nder DTE’s 2017 Reference Case, each Tier 2 unit other than St. Clair 7 incurs
net losses on behalf of DTE’s customers in every year of its remaining life. St.
Clair 7 breaks even in only 4 years and incurs net NPV losses of $10 million over
its remaining life. Importantly, under this scenario none of the Tier 2 units

The Commission’s determinations in this section are based in part on its finding that DTE
Electric’s load forecast is reasonable. The company’s load forecast is discussed below.
8

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 incur any costs associated with ELG or CPP compliance. Each unit avoids ELG
compliance costs by retiring prior to the December 31, 2023 compliance deadline.
Since the 2017 Reference case assumes that the CPP does not begin until 2027,
these units also avoid any CPP compliance costs. Yet they remain uneconomic.
5 Tr 597 (emphasis supplied, notes omitted). In addition, as DTE Electric states, environmental
compliance was not the only consideration in its retirement analysis; the company also took into
account the age of the retiring plants and their reliability and operating costs. The Commission
has also issued several decisions in rate cases expressing concern over the cost-effectiveness of
these marginal units. 9 The Commission agrees, therefore, that the most reasonable and prudent
course of action is to retire the Tier 2 units by 2023 as DTE Electric proposes.
Next, the Commission rejects ABATE’s argument that the TCJA has a significant, albeit
unquantified, effect on DTE Electric’s retirement analysis. As Mr. Chreston explained in cross
examination:
To continue to use the existing coal units, there was very little capital that would be
needed to be expended to update for environment technology, for instance, while
the proposed project had significant amounts of capital that need to be expended to
put the proposed project in place.
And it’s my understanding of reviewing the marginal cost to capital and deferred
taxes, that the heavy capital utilization for the proposed project would be more
affected by the changes in the jobs act or jobs and tax cuts act, and that would make
actually the proposed project even more favorable compared to retiring the units
due to the heavy capital utilization of installing the proposed project. So I don’t
have a specific number. But if the delta was going to change from my prior
analysis, it would be more favor for the proposed project than keeping the Tier 2
units in service.
6 Tr 1844-1845.
Next, the Commission finds unpersuasive ABATE’s claim that increased depreciation costs
make unit retirement less economical. As DTE Electric indicated, the company’s current

See, e.g., January 31, 2017 order in Case No. U-18014 and April 18, 2018 order in Case No.
U-18255.
9

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 depreciation case is pending and, under the company’s group method of depreciation, the actual
retirement date of a specific unit is immaterial. Mr. Fagan similarly points out that previously
incurred capital costs should not be included in an economic analysis because unit retirement will
not affect these sunk costs.
Finally, the Commission accepts DTE Electric’s explanation that using PROMOD for the
retirement analysis produced sufficiently robust results that further optimization with Strategist
was unnecessary. PROMOD is an appropriate modeling tool for retirement analyses of this nature.
In a related issue, Mr. Fagan suggested that DTE Electric should consider early retirement of
some of the Tier 2 units. Mr. Fagan testified that because there is sufficient available capacity in
MISO, in the near term, market purchases of capacity would be more economical than running the
Tier 2 units until 2020, 2022, or 2023. 5 Tr 585-587. Specifically, Mr. Fagan suggested that River
Rouge Unit 3 could be retired by May 31, 2018. 5 Tr 588.
In rebuttal, Ms. Dimitry testified that DTE Electric will be evaluating possible earlier
retirement of uneconomic Tier 2 units in its 2019 IRP, as required by the modeling parameters set
forth in the November 21 order. In addition, Ms. Wojtowicz testified that an operator may not
simply decide to retire or suspend operation of a unit because “local resources support the reliable
operation of the transmission system and may be required to keep it within acceptable thermal and
voltage limits.” 7 Tr 2253. Ms. Wojtowicz explained the process in MISO for evaluating
reliability, which occurs after the operator submits an Attachment Y Notification of Generator
Change of Status, noting that a unit may not retire until it is assured that the transmission system
will not be affected. Id.
The Commission agrees with DTE Electric that, although there is a possibility that one or
more of the Tier 2 units might retire early, any plans to do so should await the outcome of the

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 company’s 2019 IRP analysis and the results of MISO’s Attachment Y reliability study. Other
matters such as workforce and local government tax impacts may also be considered in a decision
of this magnitude.
The Commission finds DTE Electric demonstrated a need for power, both energy and
capacity, pursuant to Section 6s(4)(a) for purposes of granting a certificate under 6s(3)(a), largely
due to the retirement of the Tier 2 units representing approximately 2,000 MW of capacity. As
discussed further in this order, the Commission observes the “power need” may also entail the
need for local voltage support and other reliability benefits to address the closing of numerous coal
plants and integration of other resources such as wind and solar energy.
B. Does the information supplied indicate that the proposed electric generation facility will
comply with all applicable state and federal environmental standards, laws, and rules?
DTE Electric outlined how the proposed gas plant would comply with state and federal
environmental standards, laws, and rules. Mr. Marietta testified that in addition to water intake
and discharge regulations that also apply to coal-fired generation, an NGCC must also comply
with New Source Performance Standards (NSPS) under 40 CFR Part 60, Subpart 10KKKK and
National Emission Standards for Hazardous Air Pollutants (NESHAP) under 40 CFR Part 63,
Subpart YYYY. 5 Tr 1442. According to Mr. Marietta, the proposed project will comply with all
state and federal environmental regulations.
Mr. Damon testified that DTE Electric does not anticipate the need for any federal permits,
except from the Federal Aviation Administration (FAA), and will be required to obtain the
following major federal, state, and local permits: (1) Permit to Install (PTI)/New Source Review
(NSR) Air Permit from the Michigan Department of Environmental Quality (MDEQ) pursuant to
Mich Admin Code, R 336.1201; (2) Modification of the Belle River National Pollutant Discharge
Elimination System (NPDES) Permit for Water Discharge; (3) Joint Permit for Work in Inland
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 Lakes and Streams, Great Lakes, Wetlands, Floodplains, Dams, High Risk Erosion Areas, and
Critical Dune Areas from MDEQ; (4) Soil Erosion and Sediment Control and Storm Water
(NPDES II) Permits and Site Plan Preliminary Approval from the St. Clair County Drain
Commission; (5) Building Permits from East China Township, St. Clair County; and (6) FAA
authority for interference to flight path determination. 5 Tr 1469-1470.
Mr. Proudfoot concurred with Mr. Marietta that the proposed project would comply with all
state and federal environmental rules as required under MCL 460.6s(4)(b). Ms. Simpson likewise
testified that, based on the Staff’s review of the company’s state and local permit list, the proposed
project will meet all state and federal environmental requirements. 5 Tr 197-198; Exhibits S-1.2
and S-1.3. Ms. Simpson recommended that DTE Electric submit a final list of all required
environmental and construction permits and an affidavit that all necessary permits have been
acquired.
In rebuttal, Mr. Marietta apparently disputed the need to report on the permits, testifying that
all required permits were listed in the company’s initial filing and if the Staff had concerns about
any omissions, it should have raised these concerns specifically. 5 Tr 1450. In its initial brief,
DTE Electric contends that all permits will be publicly available and that “[p]ermitting is a
dynamic and time consuming process that can take years and may require modifications.” DTE
Electric’s initial brief, p. 79, note 101, citing 5 Tr 1450.
The Commission agrees with the company and the Staff that, based on the information
supplied, the proposed electric generation facility will comply with all applicable state and federal
environmental standards, laws, and rules. The Commission also agrees with the Staff’s minor
request that the company keep the Commission apprised of the status of the permitting process as
recommended by Ms. Simpson. As the company itself points out, the permitting process is

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 dynamic and there may be modifications to the initial permit applications. Thus, requiring DTE
Electric to file a list of necessary permits, updated as necessary, and an affidavit that all permits
have been obtained is not an unreasonable request.
C. Is the estimated cost of power from the proposed electric generation facility reasonable?
Under MCL 460.6s(4)(c), “The commission shall find that the cost [of the proposed
generation facility] is reasonable if, in the construction or investment in a new or existing facility,
to the extent it is commercially practicable, the estimated costs are the result of competitively bid
engineering, procurement, and construction contracts[.]” In addition to the cost information
required in the CON filing requirements as discussed above, the CON IRP guidelines require DTE
Electric to provide estimated costs of developing potential generating resources including cost
components attributable to plant capital costs, EPC, financing, specific and generalized
transmission upgrades, and owner’s costs. DTE Electric was also required to provide estimated
costs of operating potential generating resources including fuel, operations and maintenance
(O&M), and environmental compliance. December 23 order, Exhibit B, p. 3.
Mr. Fahrer described the proposed project, explaining that it will be located on 40 acres of
company-owned property adjacent to the Belle River Power Plant. Mr. Fahrer testified that the
project will be sited near existing transmission lines and high pressure gas pipeline infrastructure.
Mr. Fahrer stated that DTE Electric intends that the project be commercially available by June
2022, in time to meet the summer peak load requirements. Construction is anticipated to begin in
spring 2019. 8 Tr 2605, Exhibit A-42.
Mr. Fahrer explained the different options for contracting, ranging from owner-managed to
lump-sum turnkey (LSTK). According to Mr. Fahrer, “large combined cycle projects are
principally contracted for in today’s market based on either an owner furnished Power Island
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 Equipment (PIE) and Balance of Plant [BOP] EPC approach, or full wrap EPC option.” 8 Tr
2606. After considering the costs and risk trade-offs, Mr. Fahrer explained that:
The Company will employ an experienced EPC contractor to integrate the Owner
selected PIE, provide the balance of plant specifications, provide engineering, and
construct the Proposed Project. Under the BOP EPC approach, the EPC will
assume the performance risk associated with integration of the PIE and balance of
plant equipment with a premium to assume that risk. The Company considers the
EPC’s premium to be warranted for assuming this risk and will evaluate the risk
and cost premium for the EPC to assume a full wrap LSTK contract. The
contractual arrangement with the EPC will be a fixed price contract.
8 Tr 2607.
Mr. Fahrer indicated that the company is “pursuing a contracting strategy based on Fixed
Price Owner Furnished Equipment PIE Agreement and a EPC Balance of Plant Fixed Price
agreement[,]” using competitive bidding processes for both the PIE and EPC. Mr. Fahrer stated
that the company was also soliciting bids for a full-wrap option from EPC contractors. 8 Tr 26072608.
Mr. Fahrer estimated the capital cost of the project at $989 million, including the EPC cost of
$879 million, owner’s cost of $110 million which includes contingency of $55 million. Exhibit A43. In addition, transmission upgrades of approximately $29 million will be required but are not
included in the capital cost for the CON. Mr. Fahrer pointed out that a more definitive cost
estimate will be developed when final contract negotiations are completed after the RFP process.
8 Tr 2610.
Ms. Simpson disagreed with DTE Electric’s proposal to include 6% of estimated capital costs,
or $55 million, as contingency. Ms. Simpson testified that the contingency amount was based on
DTE Electric’s risk register which “includes 29 risk event descriptions that are evaluated for
probability and potential cost impact.” 5 Tr 203, Exhibit S-1.8. Ms. Simpson recommended that
three line items in the risk register be disallowed. Two of the disallowances concern risks that
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 could have been addressed by updating the CON at the 150-day point, which the company chose
not to do. The third involves equipment or project scope changes after negotiations are complete.
Ms. Simpson noted that because the project scope is determined at the beginning, and because
DTE Electric assigned this item the lowest risk score, the contingency associated with this item
should also be removed from the project cost estimate. In addition, Ms. Simpson pointed out that
the contracting approach the company proposes shifts the majority of risk from the company to the
contractor. Accordingly, the Staff recommended that DTE Electric’s proposed contingency costs
be reduced by $37.2 million, and the Commission should approve $951.8 million in CON costs. 5
Tr 204-206.
Mr. Damon disagreed with the Staff’s recommendation to reduce contingency, specifically the
Staff’s suggestion to remove $12 million for project scope changes. Mr. Damon testified, “Our
experience has shown that no project has been completed with zero change orders associated with
equipment selection and design changes from this early stage. Despite best efforts to identify a
detailed scope at this early stage of the project, scope decisions will still be required during
detailed design and execution.” 5 Tr 1480.
The Attorney General agreed with the Staff that contingency should be removed, contending
that the statute does not support inclusion of these costs.
The Commission finds that the base cost of the project of approximately $934 million was the
result of a fair and reasonable competitive bid process for the PIE and EPC, and there does not
appear to be any serious dispute about this issue. Accordingly, the Commission finds that the cost
of the proposed project is reasonable. In addition, the Commission agrees there should be some
allowance for contingency, and finds persuasive the Staff’s explanation that DTE Electric will bear
minimal risk based on the type of contract the company intends to enter into. Therefore, the

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 Commission adopts the Staff’s proposed contingency amount and approves $951.8 million for
costs associated with the construction of the proposed project. This equates to a cost of $865.3 per
kilowatt (kW). The Commission notes this amount does not include amounts for transmission
upgrades, which are FERC jurisdictional and subject to review as part of the MISO transmission
planning process and ITC’s Attachment O formula rate review process.
It bears emphasizing that Act 341 changed important provisions regarding the regulatory
standard for any costs ultimately incurred by the utility above the amount approved in the CON.
While the 2008 law applied a “reasonable and prudent” presumption for cost over-runs up to 110%
of the approved amount, the law now provides that any amount over the approved amount is
presumed imprudent. Thus, the utility could still seek to recover amounts, if any, above $951.8
million but it would be required to rebut this presumption.
D. Does the proposed electric generation facility represent the most reasonable and prudent means
of meeting the power need relative to other resource options?
As the Commission stated above, the primary support for a utility’s request for a CON under
Section 6s(4)(d) is the IRP. In determining whether the proposed plant is the “most reasonable
and prudent” relative to other resource options under 6s(4)(d), the Commission considered the IRP
and its underlying assumptions and consideration of alternatives, as well as modeling and other
analyses presented by the parties on substitutes for the proposed plant. These alternatives fall into
three major categories: (1) incremental renewable energy, EE, DR, and energy storage; (2) PPAs
or unit acquisition; and (3) electric transmission possibilities including additional capacity to
import power from outside the local resource zone. Thus, the Commission addresses IRP
assumptions, modeling, and results here as well as a discussion of alternatives to the proposed
plant. Section 6s(11) sets out the various components of an IRP, which the Commission addresses
in order, ad seriatim.
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 1. Long-term Forecast of DTE Electric’s Load Growth under Various Reasonable
Scenarios.
The CON IRP guidelines specify that the IRP shall include a forecast of economic indicators,
electric load including customer load and sales by customer class, peak demand, available
generation, fuel costs, and environmental costs. The guidelines outline numerous factors to
consider in the load forecast but do not specify specific forecasting methodologies or
high/base/low load growth levels. The methodologies and critical assumptions must be provided.
Mr. Leuker testified concerning DTE Electric’s method for forecasting future sales, which he
averred is consistent with accepted industry standards, and which has been consistently accurate.
8 Tr 2408, Exhibit A-19. According to Mr. Leuker, the company’s sales forecasting method
includes: (1) analysis of residential class demand considering 39 appliances or appliance groups,
number of households, appliance saturation, and electric use by appliance; (2) regression analyses
for the commercial and industrial (C&I) class by type of customer; (3) a forecast of other electric
sales (street lighting and traffic signals); and (4) the application of the hourly electric load model
(HELM) to forecast annual peak demand system annual load shape. 8 Tr 2410-2418. Mr. Leuker
also considered economic forecasts and projected population growth or decline.
As inputs to the IRP models, Mr. Leuker provided a reference scenario, a high load sensitivity
analysis, a low load sensitivity analysis, and an updated 2017 reference scenario. Exhibit A-17.
The high load analysis assumes that energy efficient lighting has reached peak market penetration,
and electric vehicles, auto and steel manufacturing, and data centers increase demand in the
residential and industrial sectors. The low load sensitivity analysis assumes a population decrease,
auto plant closures, and more customer self-generation. 8 Tr 2419-2420.
Mr. Leuker testified that overall, in the Reference Case, residential class sales are expected to
decrease 0.2% annually through 2040, commercial sales are forecast to increase 0.1% annually,
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 industrial class sales are expected to increase 0.0% through 2040, other sales are forecasted to
decrease by 0.1% annually, and choice sales are expected to stay the same over the plan period.
8 Tr 2405-2417. With respect to peak demand, DTE Electric forecast a compound annual growth
rate (CAGR) of -0.2% per year through 2040.
Mr. Neme took issue with DTE Electric’s load forecast, testifying that DTE Electric
embedded 1.15% incremental EE savings in its forecast, noting that the higher the baseline savings
the company uses, the less impact higher levels of EE will have under different modeling
scenarios. 5 Tr 373. Mr. Neme suggested that the company’s use of historical EE savings for its
projection was problematic because: (1) DTE Electric only used regression analysis for C&I
energy savings and not for forecasting residential energy sales, which comprised over half the
company’s energy savings since 2009; (2) the company did not used regression-based modeling
for all of its C&I sales; (3) DTE Electric’s regression analysis, which assumes 1.15% EE annual
savings, includes years prior to 2009 when the company was not implementing EE programs;
(4) the company’s forecast of EE savings for residential customers was incomplete and did not
account for future residential EE savings. 5 Tr 373-376.
Mr. Neme testified that, in developing its load forecast, DTE Electric should have removed the
historical effects of EE programs explaining:
Any elements of its forecast that are not based on statistical analysis of historic
sales data, such as its residential end use forecast, should be assumed not to include
any embedded future program impacts absent compelling statistical data and
analysis to the contrary. This way, the Company’s base case reference forecast
would only include impacts of historic efficiency programs – and no impacts from
any new programs. That would then allow the Company to characterize the
impacts of a full range of future efficiency program savings levels and allow its
model to select the least cost alternative from among them.
5 Tr 377.

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 In rebuttal, Mr. Leuker testified that he made the adjustments recommended by Mr. Neme and
then added a 1.50% EE assumption. Mr. Leuker testified that the result was a higher sales forecast
for both residential and total sales in the 2016 Reference Case. 8 Tr 2423-2424. In addition,
Mr. Leuker explained that a comparison of the company’s forecasted sales to load forecasts
produced by the Energy Information Administration (EIA) and MISO show that the company’s
2016 Reference Case is consistent with these projections, whereas Mr. Neme’s analysis is an
outlier. 8 Tr 2424.
Mr. Makinde testified that in the Staff’s opinion, “the Company’s projected load growth
expectations in the various scenarios are appropriate[,]” further noting, “[w]hen compared side by
side, the Company`s forecast in Exhibit A-17 and that of the EIA, Staff found that the CAGRs for
the Company and the EIA, are within a reasonable range of each other in all the cases.” 5 Tr 227
(footnote omitted), Exhibit S-2.2.
In their brief, MEC/NRDC/SC point to discrepancies between Mr. Leuker’s presentation of
energy and peak demand in Exhibit A-17 and these projections as shown in Exhibit A-10.
According to MEC/NRDC/SC, “not only do the peak demand values in the two exhibits not match
up, but the changes in peak demand over the planning period move in opposite directions.”
MEC/NRDC/SC’s initial brief, p. 18.
In response, DTE Electric highlighted Mr. Chreston’s testimony about the difficulty the
company encountered in attempting to match its presentation in Exhibit A-10 to the Commission’s
CON IRP guidelines. The company further explains: “Exhibit A-10 shows the 2017 reference
Scenario bundled peaks with 1.5% energy efficiency taken out, while Exhibit A-17 shows the
2017 reference Scenario service area peaks with 1.5% energy efficiency embedded.” DTE

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 Electric’s reply brief, p. 41. DTE Electric adds that Exhibit A-10 and A-17 serve different
purposes and “depict two entirely different representations of the peak demand.” Id.
The Commission finds that DTE Electric provided a reasonable forecast of projected load
growth under various scenarios. Specifically, the company provided a 2016 Reference Scenario, a
high load sensitivity analysis, a low load sensitivity analysis, and an updated 2017 Reference
Scenario all of which were grounded in reasonable assumptions. Mr. Neme’s proposed
modifications to the company’s load forecast resulted not only in a higher residential sales
projection but also produced a forecast that was inconsistent with forecasts by MISO and the EIA.
Accordingly, the Commission finds that DTE Electric’s load forecasts comport with MCL
460.6s(11)(a) and the CON IRP guidelines.
2. The Generation Technology Proposed, Proposed Capacity, and Projected Fuel and
Regulatory Costs under Various Reasonable Scenarios.
The primary disputes here relate to the fuel costs and the size of the proposed plant as
discussed below. With respect to fuel price forecasts and associated fuel price risk, the IRP
guidelines require the applicant to provide information on estimated fuel costs and conduct
scenario analyses to test different forecasts and assumptions. Unlike the new IRP guidelines under
Section 6t, MCL 460.6t, the IRP guidelines applicable to this proceeding do not provide any
direction on the use of specific fuel price data sources, parameters around high-base-low price
forecasts for scenario and sensitivity analysis in the modeling, or risk assessment methodologies.
December 23 order, Exhibit B.
Mr. Swiech provided delivered fossil fuel price forecasts for each existing generation facility
and fuel type for the IRP process. 10 For the natural gas price forecast for the proposed NGCC

10

Mr. Swiech’s coal and oil fuel price forecasts are not disputed.

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 plant, Mr. Swiech testified that, for the first five years, the company used the same forecasting
method it employs for its power supply cost recovery (PSCR) annual plan filings. For the longterm forecast, the company used a long-term Henry Hub price forecast plus a delivery cost adder.
8 Tr 2551.
For the proposed NGCC plant, Mr. Swiech testified that the company forecasted fuel prices
for both combustion turbine (CT) and NGCC using the Belle River peaker gas prices as a proxy.
Mr. Swiech noted, however, that an NGCC is expected to have firm transportation and storage
costs estimated at $18.5 million for transportation and $12 million for storage. 8 Tr 2553. Exhibits
A-28 and A-29.
Mr. Swiech testified that the annual delivered fuel cost is forecasted to range from $3.24 to
$7.57 per million Btu (MMBtu) from 2022 through 2040, again relying on the Belle River peakers
as a proxy for the variable fuel costs and projected fixed fuel costs of $15.7 million for
transportation and $4.5 million for storage. 8 Tr 2555, Exhibit A-30. Mr. Swiech explained that
he used New York Mercantile Exchange futures for the first five years of the forecast and then
used a long-term Henry Hub forecast from PACE Global Energy Services, LLC (PACE). 8 Tr
2552. Mr. Chreston modeled a 2016 Reference Scenario along with a low natural gas price
scenario and a high natural gas price scenario. 6 Tr 1739-1740. In order to mitigate fuel price
volatility, Mr. Swiech testified that DTE Electric intends to enter into firm transportation and
storage agreements. 8 Tr 2548, 2554. 11
Mr. Beach testified that the uncertainty and potential volatility of future natural gas prices,
which comprise over half of the life-cycle costs of the NGCC, make DTE Electric’s proposed

Issues raised by Mr. Beach and Mr. DiDomenico concerning the company’s arrangements
with the NEXUS Pipeline are addressed below.
11

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 plant too risky. 5 Tr 897. Mr. Beach provided a graph of natural gas prices at the Henry Hub over
the past several decades noting that price spikes occur regularly, highlighting the most recent spike
that occurred during the polar vortex event in January-March 2014. 5 Tr 914.
Mr. Beach took issue with some of the assumptions used in the company’s forecast, testifying
that “DTE’s reliance on more than one or two years of forward prices is questionable due to the
thinly-traded forward markets after the initial two years.” 5 Tr 915. Mr. Beach added that the long
term forecast from EIA is much higher than the proprietary forecast that DTE Electric presented.
According to Mr. Beach, under the EIA forecast, the levelized cost of the power from the plant
increases by 15%. 5 Tr 916.
Mr. Beach also took issue with DTE Electric’s ($.13) per MMBtu projection of its basis (i.e.,
the difference between the Henry Hub price and the Mich Con City Gate price) for 2023.
Mr. Beach explained that this difference was based on a sample of just one day, and is projected to
increase (become more negative) over time. Mr. Beach presented Figure 5, which demonstrates
that, over the past 10 years, the Mich Con City Gate basis differential has consistently been higher
than was projected by DTE Electric. 5 Tr 919-920.
Mr. Beach suggested that DTE Electric could address the risk of future high gas prices by
“contract[ing] today for future natural gas supplies at today’s forward gas prices, and then set aside
in risk-free investments (U.S. Treasury notes) the money needed to buy that gas in the future.”
5 Tr 916. However, Mr. Beach went on to explain “there is an additional cost of this approach,
compared to purchasing gas on an ‘as you go’ basis over time and using the money that did not
have to be set aside for alternative investments that yield a higher return[.]” 5 Tr 916. Mr. Beach
calculated the additional cost to eliminate gas price uncertainty as $86 million per year over 20
years, an amount that would increase the cost of the gas plant by 25%. 5 Tr 917-918.

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 Mr. Makinde indicated that the company’s forecast for the reference case and low-natural gas
price scenario were consistent with other industry projections. However, the company’s high
natural gas price forecast was not. According to Mr. Makinde, after applying a statistical test to
the company’s forecasts, compared to EIA forecasts, for the reference and low gas price scenarios,
“[t]he CAGR are within 0.003% of each other.” But, “[r]egarding the high gas price sensitivity,
the Company’s natural gas price CAGR (2017 to 2035) is 7.7%, however, EIA is projecting a
9.3% natural gas price CAGR[.]” 5 Tr 231. According to Mr. Makinde, “if the Company has not
adequately modeled a high gas price sensitivity, it’s possible that the Company is underestimating
the net present value of revenue requirements in the event that gas prices rise closer to the EIA’s
high gas price scenario compared to the Company’s forecasts.” 5 Tr 232, Exhibit S-2.3. Thus, if
gas prices are higher than the company modeled, the proposed NGCC may not be the most
reasonable and prudent alternative. Mr. Makinde therefore recommended that the company update
its high gas price modeling in its 2019 IRP filing.
In rebuttal, Mr. Swiech opined that Mr. Beach did not critique the company’s method for
forecasting natural gas prices, testifying that DTE Electric has compared its PSCR forecasts to
Henry Hub actual prices from 2009-2015, finding that the company’s forecast was more accurate
than the EIA forecast. 8 Tr 2560, Exhibit A-64. With respect to Mr. Beach’s critique of DTE
Electric’s projection of the Henry Hub-Mich Con City Gate differential, Mr. Swiech testified that
“[t]he decline of the MichCon City Gate basis is driven by real market changes, specifically the
dramatic growth of production in the Utica/Marcellus shale region and the increasing
transportation capacity between that region and the Midwest.” 8 Tr 2562, Exhibit A-65.
Mr. Chreston testified that he was unable to replicate Mr. Makinde’s CAGR calculation for
the High Gas Price scenario, noting that the corresponding workpaper did not match the Staff’s

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 calculation, “for the EIA high gas case should be 8.3% and the correct number for the CAGR
calculation for the DTE case should be 7.7%. This would put the difference between the two
cases at 0.6% instead of 1.6%.” 6 Tr 1818.
In its initial brief, the Staff contends that DTE Electric’s claim is unsupported and incorrect.
The Staff reiterated that “Staff took the average of the EIA high gas case annual growth rate over
the same number of years as that of the Company’s high gas case to derive the 9.3% (lines 2 to 20
of column (d) of Second Corrected Exhibit S-2.3). The difference between the two cases is 1.6%
as shown in Exhibit S-2.3.” Staff’s initial brief, p. 19.
The Commission finds that DTE Electric adequately supported its fuel price forecast
consistent with the December 23 CON IRP guidance. Although there is some dispute over the
company’s high gas price projection, the company nevertheless provided a forecast that was 40%
higher than the reference forecast. 8 Tr 2564. The Commission agrees that DTE Electric’s fuel
price forecasting method has been approved in numerous PSCR proceedings as reasonable, and
that method has proven accurate over time. Moreover, the company has plans, through firm
transportation and storage agreements, to mitigate short-term price spikes. As Mr. Swiech
explained:
While the Company’s existing natural gas fired generating facilities are currently
supplied primarily though interruptible supply arrangements, the Company expects
that electric generation in MISO will become more dependent on natural gas as a
source of fuel for base load generation in the future. As this occurs, DTE Electric
will enter into firm gas supply and gas transportation contracts as needed to ensure
electric reliability. For example, DTE Electric entered into a Precedent Agreement
with NEXUS Gas Transmission to provide firm natural gas transportation starting
upon the in-service date of the pipeline. DTE Electric’s agreement with NEXUS is
for 30,000 [dekatherms] Dth per day of transportation capacity, increasing to
75,000 Dth per day upon in-service of gas-fired generation facilities. DTE Electric
committed to firm gas transportation capacity from the Utica and Marcellus shale
region because this nearby region has new and growing production with substantial
supply and competitive pricing. Prices for natural gas from this region are expected
to remain amongst the lowest in the country for the foreseeable future.
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 8 Tr 2548-2549. And the Commission agrees with Mr. Swiech’s observation that new
development of Marcellus/Utica shale gas portends relatively low gas prices for the long term, and
the company’s access to other sources of gas supply including Canada, the Gulf Coast, and
Colorado provide an additional hedge in the event prices increase in northern Appalachia. The
Commission further observes that the company will be required to provide an analysis consistent
with the November 21 and December 20 orders in its 2019 IRP filing.
The Commission recognizes that fuel costs over the long term are a significant risk associated
with the proposed project. As explained by DTE Electric, however, the Commission observes that
there are numerous factors that mitigate fuel price volatility in Michigan generally and specifically
in relation to this plant including access to multiple gas producing markets, pipeline capacity,
long-term contracting and hedging options, and robust gas storage. 8 Tr 2553. The superior heat
rate of this plant will also ensure maximum efficiency in the conversion of natural gas to
electricity.
Turning to the issues regarding the proposed generation technology and capacity, Mr. Damon
addressed the features of the proposed plant and the consideration of alternatives such as a gasfired combustion turbine, smaller sized natural gas combined cycle plant, and energy storage.
Mr. Damon explained that:
A combined cycle power plant is based on a topping cycle wherein fuel is burned in
a combustion turbine that exhausts to a heat recovery steam generator, and a
bottoming cycle where the generated steam is used in a traditional steam turbine.
For clarity, combined cycle configurations are denoted as 1x1, 2x1 or 3x1 were
[sic] the first and last digits represent the number of combustion and steam turbines
respectively.
5 Tr 1461. Mr. Damon testified that for the alternatives analysis HDR considered other generation
technologies to evaluate their merits, costs, production, and environmental impacts. Size

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 considerations ranged from 1 MW to 1,400 MW. Id., Exhibit A-38, Exhibit A-4 (2nd Revised).
The technologies that were evaluated included five simple cycle combustion turbine options and
five combined cycle options. Simple cycle units are typically used as peakers, while combined
cycle units are able to function as intermediate or base load generators, and typically are larger
capacity as a result. Exhibit A-4 (2nd Revised) shows that the combined cycle plants have
improved fuel efficiency relative to simple cycle units, and in most cases have lower capital costs
on a $/kW basis. DTE Electric considered five generic natural gas combined cycle options in its
IRP, including F-class and H-class (2x1 and 3x1) technologies.
Mr. Damon provided an overview of the proposed project, noting that the plant is expected to
be available 87% of the time and that “[c]ombined cycle power plants are amongst the most
reliable forms of utility scale power generation technologies.” 5 Tr 1471. Mr. Damon testified
that the heat rate of the plant is projected to be at or below 6,300 Btu per kWh, and will be DTE
Electric’s most efficient generating station. According to Mr. Damon, “The plant can be operated
in base load mode or dispatched in an intermediate mode load follow mode, and as needed, at its
lowest turndown mode with one [combustion turbine generator] CTG off and the other CTG
operating at its Minimum Emission Compliance Limit (MECL) resulting in a generation output
that is about 25% of its total rated capacity.” 5 Tr 1472.
Mr. Banks testified that:
The Proposed Project plant will be able to adjust its electrical output by
100MW/minute, enough to quickly power 20,000 households per minute, over a
range of 800MW. This means that as the electrical demand adjusts up and down
the plant will operate in a flexible and reliable manner to meet the electrical
demands of customers.
7 Tr 2320 (footnote omitted).

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 According to Exhibit A-4 (2nd Revised), the proposed 2x1 H-class plant is more fuel efficient
and has a higher capacity factor than all of the other options considered, except for the 3x1 option.
Capital costs for the 3x1 H-class plant were $987 per kW versus $1,055 per kW for the 2x1 Hclass option. Although the 3x1 plant would be less expensive on a per kW basis, it would be more
expensive in total, it would result in excess capacity relative to the company’s need, and it would
take longer to build (42 months instead of 36).
The Staff raised the question of whether it is preferable to combine a smaller plant with
additional EE and DR. Mr. Banks explained:
[T]he size of the plant has been selected based on the Integrated Resource Planning
capacity need. CCGTs are designed and built in blocks based on the number of
combustion turbines that are being used in conjunction with the heat recovery steam
generators and the steam turbine. It is typical for advanced class CCGT plants to
increase their output capability in 550MW blocks. That is, for each combustion
turbine installed the output is increased by 550MW when included in a combined
cycle arrangement. Plant size is selected based on these standard designs to
promote cost minimization, efficiency, and reliability. When the Proposed Project
construction is completed and the unit is dispatched into MISO, the plant will
operate more efficiently and effectively than the other forms of electrical generation
to meet customer demand.
7 Tr 2316-2317.
Mr. Beach testified that the H-class plant is a risky investment given the lack of data on the
new class of advanced gas turbines, claiming there is little operating experience to date. 5 Tr 929.
On rebuttal, Mr. Damon responded that the proposed plant is the latest evolution of gas turbine
technology with an experienced manufacturer. Mr. Damon explained:
The General Electric 7HA.02 advanced class gas turbines selected by DTE Electric
follow a lineage of gas turbines produced by the manufacturer dating back in excess
of 50 years, with installed experience of approximately 7,000 gas turbines with over
300 million operating hours. With each progression to the next advanced gas
turbine class, General Electric has built upon technology used in earlier model gas
turbines. In addition, it is noted that with each advancement in gas turbine
technology, reliability and availability data has been maintained at a consistently
high level. The advanced gas turbine commercial fleet has over 68,000 operating
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 hours and the fleet leader has achieved rates of availability at 97.8% and reliability
at 99.7%. This exceeds the publicly available Generating Availability Data System
(GADS) publication by North American Electric Reliability Corporation (NERC)
for operating combined cycle plants.
5 Tr 1482-1483.
The Commission finds that a smaller plant was not shown to be as economical as the 1,100
MW size, and there are limitations on the size options for the combined cycle technology, as
Mr. Banks pointed out. A CT was also not as cost-effective compared to the proposed plant given
the significant need for energy and capacity. Therefore, the option of a smaller plant was
dismissed. And given the substantial near-term need to replace retiring coal plants, and the
consideration of the expected feasibility, cost, and performance of alternative options presented in
this case as discussed further below, the Commission finds, based on the evidence in this
proceeding, that the technology and capacity of the proposed plant to be the most reasonable and
prudent option.
The Commission agrees, however, with the Staff and other parties that DTE Electric’s
modeling approaches and interactions with the parties warrant attention. In particular, the
Commission is concerned that constraints placed on the models by DTE Electric, such as limiting
renewable energy to large blocks or pre-determining amounts of EE, and the utility’s selection of
optimal modeling runs limit transparency and the veracity of results. Such approaches,
particularly if not well-documented and explained, can give the impression that modeling results
were steered or forced into a pre-determined result. The Commission expects that an effective IRP
should produce results, under certain scenarios, that show the preferred course of action is not
actually the best option. This is how we know the IRP is testing the robustness of the preferred
course of action by examining how it performs under various assumptions, even if those
assumptions may seem unrealistic today.
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 The Commission expects DTE Electric to be more transparent and forthcoming with parties in
its 2019 IRP, and the company would be well-served to prioritize such stakeholder engagement
before it files its application with the Commission. The Commission also underscores the
importance of risk analysis in the IRP, especially given the dynamic nature of the energy industry
and emerging technologies. Accordingly, in preparation of the upcoming IRPs, the Commission
intends to explore with the Staff to further examine risk assessment methodologies and best
practices from other jurisdictions.
3. Projected Renewable Energy and Capacity Obtained under MCL 460.1028.
Ms. Schroeder explained that under Act 342, by 2021, DTE Electric is required to have a
renewable energy credit portfolio equal to 15% of its sales, as calculated using the number of
weather-normalized MWh of electricity sold by the electric provider during the previous year to
retail customers in Michigan, or the average number of MWh of electricity sold by the electric
provider annually during the previous three years to retail customers in Michigan. 8 Tr 2467,
Exhibits A-20 and A-21.
Ms. Schroeder testified that DTE Electric currently has a nameplate capacity of approximately
996 MW of owned or contracted renewable energy generation comprised of wind, solar, biomass
and landfill gas. This total amount includes 451 MW of company-owned wind, 458 MW of
contracted wind, approximately 64 MWAC of company-owned solar, 20 MW of contracted
biomass, and 3 MW of contracted landfill gas. 8 Tr 2469-2471.
Ms. Schroeder explained that the Commission approved DTE Electric’s renewable energy
plan in Case No. U-18111, and the plan includes an additional 300 MW of wind and 25 MWAC of
solar resources. 8 Tr 2472. For the IRP 2017 Reference Case, DTE Electric assumed an
additional 150 MW of wind and 25 MWAC of solar above what was approved in Case No.

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 U-18111. 8 Tr 2472.
No party disputed that DTE Electric correctly reported the amount of renewable energy the
company is required to provide under MCL 460.1028. Issues concerning cost and capacity
assumptions, as well as modeling renewable energy, above the statutory mandate, are addressed
below.
4. Projected Energy Efficiency Savings under MCL 460.1077.
Mr. Bilyeu provided an overview of DTE Electric’s current EE programs, which are presently
achieving 1.15% energy savings across all customer classes. No party disputed the amount of EE
savings the company is required to achieve under MCL 460.1077. 7 Tr 2008. Issues concerning
additional EE savings, above the 1% statutory mandate, are addressed below.
5. Projected Load Management and Demand Response Savings and the Projected Costs.
Mr. Kirchner provided an overview of DTE Electric’s current DR programs which include
residential, C&I, and pilot programs. Mr. Kirchner also provided the number of participants in
each program, testifying that DTE Electric’s DR program totals 572 MW of qualified resources.
7 Tr 2096-2097.
Mr. Kirchner testified that in the future, the company plans to invest in repairs to its
interruptible air conditioning (IAC) program and, in 2017, will begin a programmable
communicating thermostat (PCT) program for 10,000 residential customers. In addition,
Mr. Kirchner indicated that DTE Electric will continue to explore other DR opportunities through
pilot programs. 7 Tr 2098-2099.
For the IRP modeling in this case, Mr. Kirchner testified that in addition to the 572 MW of
existing resources, DTE Electric plans to add 125 MW of DR through the IAC upgrade program.
7 Tr 2100, Exhibit A-31. Mr. Kirchner indicated that while other DR programs were modeled in
the IRP, these programs were not selected. Mr. Kirchner concluded that the projected DR
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 included in the 2017 Reference Case totals 572 MW of existing capacity in 2017 with projected
growth of the DSM programs to 697 MW by 2021. 7 Tr 2100- 2101.
Issues and recommendations concerning additional DR are addressed below.
6. Analysis of the Availability and Costs of other Resources that could Defer, Displace, or
Partially Displace the Proposed Project.
a. Integrated Resource Plan Assumptions
Various intervenors in the proceeding took issue with the company’s assumptions about the
market price for capacity, wind and solar costs and capacity, as well as DTE Electric’s
assumptions about future PURPA resources, additional renewable energy under MCL 460.1061,
and battery storage. The issues, concerning modeling inputs rather than processes, are addressed
in this subsection.
Mr. Fagan and Mr. Allison testified that DTE Electric overstated the market price for capacity
in its modeling and questioned DTE Electric’s limitation on capacity imports to 300 MW.
According to Mr. Fagan, “these two aspects of the modeled representation of capacity imports are
critical in order to properly include, in the assessment, the availability of less-expensive purchase
capacity prior to turning to the capacity value provided by the proposed NGCC plant.” 5 Tr 571.
Mr. Fagan stated that correcting the price for capacity results in the deferral of the plant until at
least 2026. 5 Tr 572.
Mr. Allison testified that DTE Electric relied on a capacity forecast developed by PACE,
which in turn relied on forecasted reserve margins and net cost of new entry (CONE). 5 Tr 482483. Mr. Allison stated that the PACE capacity price forecast is overstated because: (1) the
forecast does not reflect historic PRA prices, which are 50%-125% lower than the PACE forecast;
(2) DTE Electric has a history of forecasting higher-than-actual capacity prices as demonstrated in
the company’s PSCR plan and reconciliation filings; (3) there are expectations that resource
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 adequacy in MISO will be sufficient; and (4) some of the assumptions in the PACE model were
poorly supported. 5 Tr 484, 486, 487-488, 491-492.
In rebuttal, Ms. Wojtowicz explained that both Mr. Fagan and Mr. Allison largely base their
criticisms on MISO PRA prices that are much lower than DTE Electric’s forecast, although the
PRA is irrelevant. Ms. Wojtowicz testified that under MCL 460.6w, the company is required to
demonstrate capacity four years into the future, and the company cannot rely on the PRA to make
this demonstration. Ms. Wojtowicz added that the PRA is capped at CONE for a CT and therefore
does not reflect the cost of baseload generation that the company intends to retire and build. 7 Tr
2240. According to Ms. Wojtowicz, a more realistic comparison for capacity prices can be found
in the results of a reverse capacity auction in summer 2017 for capacity purchases in 2018/2019
through 2022/2023. “Results of the Company’s 2017 reverse capacity auction indicated steadily
rising capacity prices throughout the next four years, culminating in an average offer price above
$50k/MW-yr for the 2021/22 Planning Year.” 7 Tr 2241. Ms. Wojtowicz added that even with
the addition of the proposed project, the capacity resources in LRZ 7 are not expected to be
sufficient to meet the LCR in 2023/24, thus placing upward pressure on the cost of capacity. 7 Tr
2241-2242, Exhibit A-55.
Ms. Schroeder testified that the 2017 Reference Scenario includes all wind and solar resources
required to meet the mandate under 2008 PA 295 as amended by Act 342. 8 Tr 2472.
Ms. Schroeder further indicated that a High Renewables sensitivity that incorporates 1,500 MW of
renewables above the Reference Case was modeled. According to Ms. Schroeder, consistent with
the 35% goal outlined in Section 1 of Act 295, MCL 460.1001, the company expects that the
combined renewable and EE portfolio in this IRP will meet the goal by 2025. 8 Tr 2473.

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 Ms. Schroeder testified that for cost assumptions associated with additional wind energy, DTE
Electric used 2016 actual installed costs of $2,150 per kW, with costs declining based on estimates
of future market costs. In addition, for all scenarios, DTE Electric assumed a net capacity factor
(NCF) of 41%, cautioning that this is based on a wind farm in the most appropriate area for wind
generation, and “wind parks developed through 2025 [are expected] to be located outside of the
Thumb region, due to the Huron County voter referendum and local community resistance in the
Thumb region.” Thus, “future wind parks will likely have a lower NCF[.]” 8 Tr 2473-2474.
Ms. Schroeder testified that annual O&M and capital maintenance expenses, are estimated to
be $16 and $20 per kW respectively and that these amounts are assumed to increase with inflation.
With respect to the PTC, Ms. Schroeder explained that the 2018 wind park is assumed to receive
100% of the credit, and the 2020 wind park is assumed to receive 60% of the credit. 8 Tr 24742475.
For solar, Ms. Schroeder used 2016 actual installed costs of $1,900 per kWAC as the baseline,
and compared its internal forecasts, based on experience to date, with Navigant Consulting’s
utility scale forecast from its 2016 report, “U.S. Distributed Renewables Deployment Forecast.”
8 Tr 2475. Exhibit A-23. Ms. Schroeder further testified that DTE Electric “expects future solar
parks to operate at a 20% NCFAC based on the Company’s experience with fixed tilt ground
mounted systems in Michigan.” Id.
Ms. Hunt observed that although DTE Electric started its analysis of wind costs with the
company’s recent experience, several reliable sources report lower baseline costs for the Midwest.
For example, Lawrence Berkeley National Laboratory (LBNL) reported an average installed cost
for wind projects of $1,711 per kW for projects completed in 2016 in the Great Lakes Region,
reporting that no project had a cost that exceeded $2,100 per kW installed. 5 Tr 632. In addition,

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 the National Renewable Energy Laboratory (NREL) reported a national installed cost range of
$1,737-$2,109 per kW, and EIA reported an average national installed cost for 2016 of $1,877 per
kW. Id. Similarly, Ms. Hunt testified that DTE Electric’s projected wind cost for 2018 of $1,828
per kW installed, was also relatively more expensive than other reported sources, as were the
company’s capital maintenance and O&M costs. According to Ms. Hunt, “Overall, market data
suggest that, given expected O&M cost declines in the future, DTE Electric should consider
reevaluating its O&M costs assumptions, including adding a de-escalation factor, similar to its
installed cost assumptions.” 5 Tr 634. Ms. Hunt testified that DTE Electric calculated a levelized
cost of energy (LCOE) of $47 per MWh with the PTC and $70 per MWh without the credit.
Again, Ms. Hunt pointed out that this was high in comparison to other sources.
Ms. Schroeder disagreed, noting that the company’s basis for the Reference Cases’ installed
wind costs was a 2016 wind park that was competitively bid and audited by the Staff. For 2018
installed costs, the company again used a company project that had been competitively bid and
audited. 8 Tr 2480. Ms. Schroeder reiterated that the company’s 2020 wind project, which
qualifies for 100% of the PTC, has an LCOE of $46 to $48, which is in line with the projection
used in the models and consistent with other projections.
Mr. Lucas disputed DTE Electric’s assumptions about solar technology. First, Mr. Lucas
noted that DTE Electric used a 20-year life for new solar installations, explaining that although
solar PPAs are often for 20 years, some solar panels have warranties of 25 years. 5 Tr 717. Next,
Mr. Lucas testified that, in its Reference Case, the company used an annual panel degradation rate
of 0.80%, which is higher than generally assumed. While DTE Electric updated the degradation
rate to a more typical 0.50% in its 2017 Reference Case, Mr. Lucas pointed out that the company
did the majority of its modeling using the 2016 Reference Case. 5 Tr 718. Mr. Lucas testified that

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 accurate assumptions about panel life and panel degradation are a critical aspect of calculating
solar costs, observing that increasing panel life and decreasing degradation are an important focus
in the solar panel industry today. Id.
Mr. Lucas also questioned DTE Electric’s assumption that only south-facing, fixed-tilt
systems would be installed, testifying that the company is proposing the new plant to supply both
energy and capacity. Mr. Lucas testified that while south-facing systems maximize the amount of
energy production from solar, much higher capacity, as well as more energy, can be attained
through the installation of single axis tracking systems. 5 Tr 720-721. Mr. Lucas indicated
information from the FERC that shows the rapid adoption of single-axis tracking systems. 5 Tr
721.
Using Michigan-specific information, Mr. Lucas modeled several different solar systems,
including single axis and double axis tracking. “Among fixed-tilt systems, south-facing was the
worst choice for DTE’s capacity needs. While this orientation did produce more energy than
southwest or west-facing fixed-tilt systems, it contributed much less capacity.” 5 Tr 723.
Mr. Allison testified that DTE Electric used different assumptions for solar capital costs at
different points in its testimony, workpapers, and modeling. Mr. Allison pointed to a discrepancy
between the amounts for solar installed costs in Exhibit A-23 and Mr. Chreston’s workpapers
containing solar cost assumptions. 5 Tr 455. While Mr. Allison agreed with DTE Electric’s use of
an “aggressive” cost decrease assumption for solar, he provided a graph that shows that the
company’s near-term solar costs are 24% higher than those forecasted by NREL, thus biasing its
analysis against near-term selection of solar resources. 5 Tr 455-456. Mr. Allison also pointed to
inconsistencies between Ms. Schroeder’s testimony about O&M costs and the much higher O&M
costs used in the modeling scenarios. 5 Tr 457. Mr. Allison testified that although DTE Electric

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 corrected the error, he was not aware that the company re-ran any of the models with the corrected
O&M amount. 5 Tr 458.
Mr. Allison echoed Mr. Lucas’ concerns about DTE Electric’s assumed capacity factor of
41% for new solar facilities, despite MISO’s use of a default capacity credit of 50% for new solar.
Mr. Allison testified that the use of the lower capacity factor failed to take into account solar
technology improvements, and that it was based on the performance of just one of the company’s
solar installations. Mr. Allison opined that it is not appropriate to make projections on the basis of
the performance of a single project and that the MISO default is based on a class average. 5 Tr
459-460.
In rebuttal, Ms. Schroeder testified that the company’s installed cost for solar was a reasonable
starting point for the projection, and that the company’s “aggressive” cost-reduction scenario was
in fact the most aggressive forecast available at the time the modeling was performed.
Ms. Schroeder pointed out that the sources cited by Mr. Allison were only recently published.
Mr. Jester testified that DTE Electric’s assumption that no additional renewable energy will be
required under the customer-requested green energy provisions of MCL 460.1061 is erroneous.
According to Mr. Jester, customer demand for additional renewable power is growing nationally
and should be expected to increase in Michigan as well. Mr. Jester also contended that DTE
Electric’s failure to include new and existing PURPA contracts in its analysis was unreasonable,
noting that DTE Electric’s modeling assumed that existing PURPA contracts will begin to expire
in 2024 and will not be renewed. Mr. Jester also pointed to significant interest in new PURPA
development as a result of DTE Electric’s avoided cost proceeding in Case No. U-18091.
In rebuttal, Mr. Bloch testified that it was unreasonable to expect expiring PURPA contracts to
be renewed, noting that 95% of DTE Electric’s 104 MW PURPA contract portfolio includes

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 landfill gas and municipal solid waste, energy sources that may no longer be available when the
contracts expire. 8 Tr 2348. In addition, Mr. Bloch pointed out that the company’s PURPA
avoided cost case is still pending and that the company disputes the method for establishing
avoided cost rates. 8 Tr 2350-2351.
Mr. Jacobs provided an overview of commercially available battery storage resources that are
being cost-effectively deployed around the country. Mr. Jacobs opined that although DTE Electric
considered battery storage in its IRP, the company dismissed this option without sufficient
justification. 5 Tr 879-880.
Mr. Jacobs highlighted the benefits of battery storage, including rapid incremental
development, flexibility, grid services (i.e., congestion relief) and ancillary services such as
frequency regulation. Mr. Jacobs added that the value of ancillary services is recognized in the
market. 5 Tr 880-881.
Mr. Jacobs testified that the cost of battery storage is projected to decline significantly over
the next five years as reported in the Lazard annual Levelized Cost of Storage reports. According
to Mr. Jacobs, these reports for 2015, 2016, and 2017 project cumulative cost reductions for
lithium-ion battery systems of 47%, 38%, and 36% respectively. Other projections from
Bloomberg, Navigant, and Greentech Media project similar cost reductions. 5 Tr 883-884.
Mr. Jacobs testified that several other utilities in the United States have updated their IRPs to
include battery storage as a resource option, noting that Indiana Power and Light’s base IRP calls
for an increase of 500 MW in storage capability; Arizona Public Service added a similar amount to
its IRP; Portland General Electric is proposing to add at least 5 MW-hours of storage; and Public
Service Co. of New Mexico is issuing an RFP for new storage, renewables and flexible natural
gas. 5 Tr 887.

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 Mr. Jacobs testified that although DTE Electric initially considered battery storage as an
option, the technology did not pass the first screen and thus was not selected for further evaluation.
Mr. Jacobs opined that DTE Electric’s assumptions about the future cost decline of storage likely
led to this result. According to Mr. Jacobs, DTE Electric assumed battery costs would decrease by
26% over 5 years, a significantly lower decline (and therefore higher storage cost) than is seen in
other projections. 5 Tr 889. Mr. Jacobs also pointed out that DTE Electric’s Strategist modeling
did not include the ancillary service and flexibility values associated with storage. Thus,
Mr. Jacobs testified that DTE Electric undervalued battery storage by failing to include a
reasonable analysis of the benefits of this technology. 5 Tr 895.
In rebuttal, Mr. Chreston testified that while some utilities have included storage as a resource
in their IRPs, most have other compelling reasons to do so, including significant renewable energy
additions, transmission benefits, or policy mandates. Mr. Chreston added that of the utilities
Mr. Jacobs cites, most do not plan to add storage until the mid-2020s or later. 6 Tr 1803-1804.
Mr. Chreston further testified that the company’s assumptions about the declining cost of storage
were reasonable at the time they were made; however, “[w]hile batteries are still a high cost
resource relative to other options, as technologies continue to improve and costs decline, the
Company will continue to evaluate their potential role in our portfolio.” 6 Tr 1805.
Discussion
The Commission finds DTE Electric’s modeling assumptions to be reasonable for the portion
of the IRP that addresses the timeframe in which the plant will be built (i.e., until 2022). First,
with respect to capacity costs, the Commission agrees with the company, that use of the MISO
PRA as a comparison to capacity cost is inappropriate. The PRA functions as a balancing market
for small capacity purchases and therefore does not approximate the needs that the company will

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 have with the Tier 2 unit retirements. In addition, as DTE Electric points out, under MCL 460.6w,
the company is required to demonstrate capacity four years into the future, and that cannot be
accomplished using the PRA. Therefore, the Commission finds DTE Electric’s capacity cost
assumption, based on the company’s 2016 reverse capacity auction is reasonable.
With respect to wind resources, the Commission agrees with DTE Electric that basing its
projection of the future cost of wind energy on the company’s most recent wind farm costs
resulted in costs that are only slightly above the high end of the range of wind energy installed
costs that Ms. Hunt reported. Moreover, as DTE Electric points out, although the company
assumed a 41% capacity factor based on Huron County production, local siting restrictions have
prevented new wind energy developments in this optimal wind zone, and future wind parks,
located outside this area, may not achieve capacity levels as high as 41%. Thus, DTE Electric’s
perhaps optimistic assumption about net capacity, to some degree, offsets the company’s higher
assumed costs. The Commission also finds that DTE Electric’s LCOE with and without the PTC
are near, or within, the ranges that Ms. Hunt reported for comparison purposes.
Similarly, for installed solar costs, the Commission finds the company’s use of its own
installed solar costs, and projection of future costs, to be reasonable. DTE Electric plausibly based
its projection on the company’s own experience including actual operational experience with solar
tracking systems in Michigan’s climate. In addition, DTE Electric used several credible sources to
inform its solar cost projections. Moreover, in light of rapid cost reductions in solar technology,
the company states that it intends to undertake further evaluation of the technology.
With respect to assumptions about additional renewable generation resulting from customerrequested green energy under MCL 460.1061, the Commission agrees with the company that Mr.
Jester’s projection is overly optimistic. Given the difficulty in making predictions of customer

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 interest, the Commission does not believe it is prudent to plan on a significant increase in Section
61 renewable energy between now and 2022, because these programs are still under development,
with Commission decisions expected in the fall of 2018. Nevertheless, the Commission expects
additional information about customer interest in this optional program may be available by DTE
Electric’s 2019 IRP filing, where this assumption can be further tested. DTE Electric also
included 300 MW of wind energy for green pricing programs in its recently filed renewable
energy plan in Case No. U-18232.
The Commission agrees ELPC et al., Ann Arbor and EIBC, that DTE Electric did not provide
strong support for its assumption that current PURPA contracts will not be renewed; the
Commission finds this assumption to be inappropriate as a matter of policy but nevertheless notes
that most of DTE Electric’s PURPA contracts are not set to expire until after the company
completes its 2019 IRP and that they represent a relatively small amount of energy and capacity.
By the 2019 IRP filing, changes, if any, to PURPA should be known and addressed in that
proceeding. If there are no changes, the Commission agrees with ELPC, et al. that the appropriate
assumption is that the law will continue as it currently is and that the contracts will be renewed.
With respect to new PURPA contracts, the Commission agrees with Mr. Jester’s observation
that:
The interplay between PURPA avoided cost proceedings and consideration of
utility proposals for Certificates of Necessity or through Integrated Resource
Planning raises the potential for conflict, requiring careful consideration in all
relevant proceedings, including this one. If the utility states in its PURPA
proceedings that it does not forecast capacity needs from PURPA qualifying
facilities because it has plans to acquire non-PURPA capacity, while at the same
time the utility states in a Certificate of Necessity proceeding that it does not
forecast PURPA resources in its integrated resource planning and therefore must
build other resources, were the Commission to accept both statements, this may
result in sanctioned discrimination by the utility against PURPA qualifying
facilities and fully undermined PURPA’s intent.

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 5 Tr 431-432.
Exhibit ELP-65 contains a notification from DTE Energy to potential QFs that the utility does
not have a need for capacity over the next ten years. The Commission finds that it is inappropriate
for DTE Electric to publish such a statement without a determination from the Commission that
the utility, in fact, does not have a capacity need over the next 10 years.

DTE Electric’s actions

are especially troubling given the utility’s obligations under PURPA, the capacity need
determinations by the Commission in DTE Electric’s pending PURPA case, Case No. U-18091,
and the information in this docket filed by the company identifying a near-term need incremental
to the proposed gas plant. Ms. Dimitry testified that the Company’s expected resource
requirements for energy and capacity would most prudently be addressed by the proposed 1,100
MW NGCC, with DR and minor market purchases or other resources up to 300 MW being used to
make up any remaining energy and capacity needs. 6 Tr 1609. Mr. Chreston further elaborates
on the remaining 300 MW capacity need, testifying that “[e]ven though the modeling assumes that
the amount would be filled by market purchases, it should be thought of as an open position that
can be filled by smaller economic resources determined at a later date. These resources could
consist of a portfolio of renewables, CHP, DG, or demand response options in addition to market
purchases.” 6 Tr 1742-1743.
The Commission acknowledges that potential benefits may exist to remain flexible and
determine specific plans for the remaining capacity need at a later date, and the Commission
expects that DTE Electric has every intention of filling the remaining capacity need with resources
at an appropriate point in the future. However, DTE Electric’s intentions to fill that capacity need
at some future date do not alleviate the company’s obligations under PURPA. Therefore, the
Commission finds that absent action by DTE Electric to address its plans for meeting its capacity

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 needs over the 10-year horizon and make associated commitments through applicable regulatory
filings, the Commission’s determination of need in this proceeding, based on DTE’s evidence with
a near-term need of 300 MW in the early 2020s, serves as the Commission’s current determination
of the company’s capacity need over the 10-year period. 12 The Commission notes that it may
further explore issues surrounding how capacity determinations are made for purposes of PURPA
in U-20095, rulemakings or other proceedings.
Finally, with respect to battery storage, the Commission is not inclined to write off this
emerging technology as lightly as DTE Electric, who dismisses storage with, “this is not Shark
Tank” in its reply brief, p. 70. Nevertheless, the Commission finds persuasive the company’s
testimony that the utilities that are planning the addition of utility-scale storage are not intending to
do so until the mid-2020s or later. In its 2019 IRP, DTE Electric is expected to include a better
evaluation of storage options, including a quantification of storage benefits including flexibility,
grid support, and ancillary services as outlined in Mr. Jacobs’ testimony.
b. Integrated Resource Plan Scenarios, Sensitivity Analyses, and Results
Once IRP assumptions are established, as discussed above, the next step is to model various
scenarios and sensitivity analyses. Mr. Chreston testified that the purpose of an IRP is to
determine if additional resources are required to meet the energy and capacity needs of the utility’s
customers and, if so, additional analyses are undertaken to determine the most reasonable and
prudent means to meet those needs. 6 Tr 1712. Mr. Chreston identified the steps taken in the
modeling process as: (1) evaluating the company’s capacity position; (2) determining alternative
resource options; (3) developing model assumptions including scenarios and sensitivity analyses;

DTE Electric’s analysis includes the assumed retirement of Belle River Unit 1 on May 31,
2029 and Belle River Unit 2 on May 31, 2030. 6 Tr 1730
12

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 (4) modeling and analyzing results; (5) assessing other considerations; (6) undertaking a risk
analysis; and (7) identifying the proposed course of action. 6 Tr 1712-1713.
Mr. Chreston testified that in determining resource alternatives to address capacity needs, the
company evaluated several technologies including natural gas, coal, nuclear, renewables and
demand side management resources. For each option, the company calculated the levelized cost of
energy (LCOE), and eliminated options with the highest LCOE. The remaining technologies that
were evaluated further were natural gas CT, NGCC, renewables (wind and solar), EE, DR, storage,
customer-owned generation, transmission, distribution efficiency, and short-term market purchases
of 300 MW based on import limits and capacity availability in MISO. 6 Tr 1721-28; Exhibit A-4
2nd Revised, Table 10.10-1. Mr. Chreston added that the company also considered a no-build
option, but determined that even under the most aggressive EE and DR programs “the retiring coal
capacity would still leave a shortfall of approximately 900 MW by 2023.” 6 Tr 1724.
Mr. Chreston explained that the company modeled both scenarios and sensitivities and that
“[s]cenarios are futures that affect market and commodity prices on a broad basis[,] which include,
“assumptions pertaining to Environmental legislation, commodity supply and demand, new
resource capital costs and existing unit retirements[.]” 6 Tr 1733. On the other hand, sensitivities
“are more Company specific variables that only affect the DTE Electric service territory and/or
Michigan.” 6 Tr 1733-1734.
Mr. Chreston testified that the modeling looked at five scenarios: Reference Case, High Gas
Prices, Low Gas Prices, Emerging Technology, and Aggressive CO2. The company also modeled
eight different sensitivities including high and low load growth, higher renewable energy mandate,
EE, higher NGCC capital costs, NGCC size, electric choice return, CO2 reduction, and a new
nuclear plant. 6 Tr 1734-1737. Mr. Chreston noted that not every sensitivity was run on every

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 scenario, however most were run on the Reference Case, because that was considered the most
likely future scenario. Mr. Chreston indicated that in the end, over 50 different model runs were
completed using various combinations of assumptions. 6 Tr 1737-1738. Mr. Chreston added that
after new energy legislation was enacted in 2016, a 2017 Reference Case was developed
containing updated assumptions for market prices, load forecast, fuel prices, EE and Renewables.
The 2017 Reference Case did not change the prior outcome that showed that a 1,100 MW NGCC
should be added. 6 Tr 1739, Exhibit A-4, 2nd Revised, Section 12.2.
Mr. Chreston explained how various load, fuel, and market price assumptions were developed,
testifying that for capacity prices, the company used market forecasts developed by PACE.
Mr. Chreston testified:
After the energy market is determined, net CONE is calculated for a CCGT unit.
Net CONE is the “Cost of new entry” less the energy margins. The amount of
reserve margin in zone 7 is also determined for each scenario. If the reserve margin
is low, then the capacity price is set closer to the net CONE value. If there is
sufficient capacity built in the zone, the capacity price is a fraction of the net CONE
price.
6 Tr 1741.
Mr. Chreston reiterated that up to 300 MW of capacity purchases were allowed in any year in
the various scenarios and sensitivities, noting, “Even though the modeling assumes that the
amount would be filled by market purchases, it should be thought of as an open position that can
be filled by smaller economic resources determined at a later date. These resources could consist
of a portfolio of renewables, [combined heat and power] CHP, DG, or demand response options in
addition to market purchases.” 6 Tr 1742-1743.
Mr. Chreston described the process and results of the company’s modeling, explaining that:
[A]ll technologies that were determined to be commercially viable and technically
feasible were evaluated through LCOE analysis and Market Valuation. Once the
least economic technologies and resources were screened out, the remaining
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 resources were put into the Strategist® optimization, resulting in the selection of
resource plans for each scenario and sensitivity.
6 Tr 1746. Additional factors were also considered in determining the resource plan including
“reliability, affordability, clean, flexible and balanced, compliant and reasonable risk.” 7 Tr 1747.
Mr. Chreston testified that the selected plan under the Reference Case includes 100 MW of
incremental solar by 2021; 150 MW of incremental demand response program expansion by 2021;
1,100 MW NGCC plants in 2022 and 2029, 500 MW of additional wind by 2025, and 1.50% EE
savings. 6 Tr 1752.
Mr. Chreston testified that the 1.5% EE savings level was the most cost-effective level on an
NPV basis, and had the highest benefit cost ratio. Under all scenarios and thirty sensitivities, the
optimum level of EE was 1.5% and two NGCC plants were selected for 2022 and 2029. 6 Tr
1753-1756, Exhibit A-8.
Mr. Chreston stated that although the Strategist modeling was largely based on modeling
constraints and quantitative inputs, “The other factors of Clean, Flexible and Balanced, and
Reasonable Risk must either be handled more qualitatively outside the Strategist® model or by
using techniques that quantify these in a way that rates alternative portfolios against each other
based on how they perform[.] 7 Tr 1757. Mr. Chreston explained that the risk analysis was a fourpart inquiry:
The first was a Stochastic analysis, which focused on maintaining or minimizing
the “Reasonable Risk” principle. The second was an Analytic Hierarchy Process
(AHP) analysis. The AHP analysis quantified and optimized the principles of
affordability, clean, flexible and balanced, and reasonable risk. The third part was a
refresh of our Reference scenario (i.e., 2017 Reference scenario) with the latest
assumptions available since the modeling assumptions from the five scenarios had
originally been locked in as of June 2016. Lastly, we completed a Change analysis
that considers how adaptable the plan is to new inputs and changes to the
assumptions.
6 Tr 1757-1758.
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 Mr. Chreston explained the Stochastic, AHP, and Change analyses, as well as the Reference
update. 7 Tr 1758-1767. Mr. Chreston testified that under the Change analysis risk review:
In the high load and both choice return sensitivities, additional resources are
needed, and CC technology is still selected. In the low load and the 2% EE
sensitivities, the CC technology is still selected, however it is delayed one year. If
future signposts indicate that the load is higher than forecast or choice load is
known to be returning, then the increased need for capacity can be mitigated by
issuing a RFP for added capacity to bridge until the next IRP is completed.
Similarly, if sales are lower than forecasted, then economic analysis could be done
to determine the value in delaying the Proposed Project one year. The value of the
delay would be offset by the risk of the remaining tier 2 coal units needing to retire
earlier than 2023 and potential EPC cost increase.
7 Tr 1767. Mr. Chreston concluded that overall, the risk analyses “support that the proposed plan
is economic under a variety of situations, and is robust and prudent.” Id., Exhibit A-6 and Exhibit
A-10 3rd Revised.
Finally, Mr. Chreston provided the calculation of the revenue requirement for the project
including rate base, O&M costs, and net PSCR impact compared to a no-build option.
Mr. Chreston testified that the result of the comparison showed a benefit to customers of
approximately $33 million in the first operating year of the plant. 6 Tr 1770, Exhibit A-9.
Ms. Gould testified that DTE Electric modeled “planned” renewables, energy efficiency and
DR in its IRP, opining that the use of the word “planned” indicates that “the levels of these energy
resources were calculated prior to inputting them into the modelling.” 5 Tr 242-243. Ms. Gould
explained that by considering energy efficiency a demand-side resource rather than a supply-side
resource, EE was never maximized as an alternative to the proposed project. Ms. Gould further
testified that DTE Electric failed to adequately evaluate EE savings above 1.5%, noting that the
difference in the NPV between 1.5% and 2% energy efficiency savings is minimal and that certain
savings, such as reduced fuel imports and lower CO2 emissions, are not fully captured in the

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 analysis. In addition, DTE Electric did not include more EE in its high gas price scenario, even
though savings would be greater. 5 Tr 244.
Ms. Gould testified that the updated Michigan Lower Peninsula Electric Energy Efficiency
Potential Study determined that DTE could meet an EE savings target of 2% through 2026 or
longer. 5 Tr 245, Exhibit S-3.2. Ms. Gould admitted that 2016 PA 342 requires EE savings of
1%, however, the company receives a financial award if it achieves savings of an additional
0.50%. Ms. Gould testified that the Staff fully supports an EE savings level of 2% in DTE
Electric’s IRP, disputing the company’s claim that ramping up from 1.5% to 2% would be
administratively burdensome and difficult for vendors. She further testified that Mr. Bilyeu’s
testimony shows that over 20 years, the cost for 2% energy efficiency savings is less than the cost
for 1.5% energy savings over the same time period. Ms. Gould also highlighted the minimal
difference in the UCT scores for 1.5% versus 2.0% savings. 5 Tr 249-250.
Ms. Gould admitted that EE savings could not substitute for the full amount of the company’s
capacity need, “but even nominal increases of EWR provide security and stability for the
Company in meeting the energy needs of their customers.” 5 Tr 252. Ms. Gould therefore
recommended that the Commission condition approval of the CONs on a requirement that DTE
Electric implement 2% EE savings.
Mr. Neme similarly took issue with DTE Electric’s assumptions about achievable EE savings
between now and 2030 are far too conservative, and that a more aggressive EE strategy could
defer the proposed NGCC plant until 2030 with significant customer savings. Mr. Neme pointed
out that the EE potential study on which the company relied only looked at EE potential based on
the current incentive levels the company provides under its programs. 5 Tr 380. Thus, Mr. Neme
testified that the study, like most potential studies, does not reflect the significantly larger amount

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 of EE that is cost-effectively achievable. 5 Tr 381. Mr. Neme pointed to Massachusetts which he
testified is one of the few states where utilities are attempting to capture all cost-effective EE
savings. 5 Tr 382-383.
Mr. Neme explained that there are a number of reasons why EE potential studies result in
conservative estimates of energy savings including a focus on known measures while excluding
emerging technologies, a failure to capture savings from “custom” measures that are unique to a
single site or industry, a failure to account for increased savings or decreased costs of particular
measures over time, and placing artificial limitations on the amount of financial incentive that can
be offered for adoption of EE measures. 5 Tr 384-386.
Mr. Neme pointed out that DTE Electric’s most aggressive EE scenario (2% EE savings) still
produced a very high benefit cost ratio of 7.95, observing, “with a benefit-cost ratio of almost 8 to
1, the Company could have doubled its assumed financial incentive levels for every efficiency
measure – with related increases in program participation and savings levels – and still saved at
least four dollars in avoided energy supply costs for every dollar spent.” 5 Tr 387-388.
In rebuttal, Mr. Bilyeu testified that Ms. Gould’s 2% EE proposal is inappropriate because the
company has demonstrated that 1.5% EE is most reasonable and most likely to deliver the
projected energy savings; the company already has an approved plan for 2018-2019; and DTE
Electric will be filing another IRP in March 2019.
In response to Mr. Neme, Mr. Bilyeu testified that an incentive level of 50% of measure cost
is reasonable based on its own and other EE potential studies, and that the higher incentive
payments that Mr. Neme suggests are unnecessary to achieve higher savings. 7 Tr 2029.
Mr. Bilyeu reiterated that DTE Electric’s focus was on achieving aggressive levels of EE savings
while remaining cost-effective, as evidenced by the American Council for an

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 Energy-Efficient Economy (ACEEE) 2017 Utility Energy Efficiency Scorecard, which compared
DTE Electric to 52 other utilities. 7 Tr 2031.
Ms. Smith outlined DTE Electric’s current DR program, focusing specifically on the
company’s interruptible air conditioning program (IAC). Ms. Smith explained that DTE Electric
is planning to add 125 MW to its DR portfolio through repairing switches in its existing IAC
program. Ms. Smith questioned DTE Electric’s explanation that the IAC program is capped in the
company’s tariff, noting that the limit on participation is self-imposed. Ms. Smith pointed out that
she was unaware of any cost-of-service reason to cap IAC program participation. 5 Tr 257-258.
Ms. Smith disputed DTE Electric’s claim that its proposed DR program was in line with the
company’s most recent potential study, observing that the potential study projects achievable DR
of 825 MW by 2020, whereas the company only plans to attain 697 MW by 2021. Moreover, the
State of Michigan Demand Response Potential Study identified 991MW of DR potential by 2020,
which would be 386 MW over the company’s baseline. 5 Tr 259-260. Ms. Smith summarized:
The Company can improve and expand their existing DR programs in a costeffective manner. Further, Staff believes the Company did not fully assess for
modelling purposes of this certificate of need filing that DR in conjunction with
Energy Waste Reduction and Renewable Energy could provide a cost-effective
solution to reducing the size of a gas plant needed to fill capacity shortfalls, and
could delay a construction start date, all while enhancing distribution reliability and
stability in their service territory and should be considered in the Company’s IRP as
a packaged resource which competes with other generation resources.
5 Tr 261.
Mr. Jester testified that, with respect to DR, DTE Electric “omits the lowest-cost and largest
opportunities for additional demand response[,]” observing that the Statewide Demand Response
Study from 2017 shows much higher potential for DR than the study that the company relies upon.
5 Tr 420-421. Exhibit MEC-42. Mr. Jester points out that the “Low Realistic Potential” in the
statewide study shows a much higher DR potential than the company assumes. “At a minimum,
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 for the purposes of DTE’s current plan, the Low Realistic Potential in the Commission’s study
should be considered as available resources for a “most reasonable and prudent” plan, followed by
consideration of the implementation of additional efforts[.]” 5 Tr 421. The Low Realistic
Potential considers 10 existing and new programs and results in additional DR of 265 MW in 2018
escalating to 1,339 MW in 2037. 5 Tr 422, Table 5-10.
With respect to the costs of DR, Mr. Jester testified that although DTE Electric evaluated a
number of DR programs in its IRP, the company failed to consider programs that are considered
least-cost options, such as real time pricing, time-of-use (TOU) rates, and variable peak pricing.
5 Tr 423, Table 5-5. Mr. Jester stated that based on his recommendations, DTE could have
available an additional 335 MW of DR in 2023. 5 Tr 424.
Mr. Jester testified that he included two sets of DR assumptions to Mr. Evans: a High
Realistic Potential DR and a Low Realistic Potential DR. 5 Tr 426. Exhibit MEC-46. By
inputting the Low Realistic Potential DR to the model, Mr. Evans was able to demonstrate that the
plant could be delayed until 2023.
Mr. DiDomenico pointed out that DTE Electric should have included an additional 138 MW
of UCAP in its 2017 reference case to reflect the company’s planned investments in PCT and other
new DR programs.
Mr. Kirchner responded that the new programs were modeled in the 2017 Reference Case but
were not selected. 7 Tr 2107. Mr. Kirchner further pointed out that unlike EE programs, DR
programs require regulatory approval and cost recovery through rate cases. 7 Tr 2107-2108. In
response to Ms. Smith, Mr. Kirchner testified that DTE Electric has not “capped” the IAC
program, but the company does not expect more customer participation given the availability of
alternatives like the PCT program. 7 Tr 2108.

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 In response to Mr. Jester, Mr. Kirchner stated that the statewide potential study assumes that
450,000 DTE Electric customers will sign up for TOU rates in the next four years, a completely
unrealistic assumption. The statewide study further assumes that DTE Electric has 68 MW of
direct load control hot water heating by 2023, even though only 0.5% of the company’s sales
forecast includes hot water. 7 Tr 2110.
Mr. Harlow testified that DTE Electric failed to analyze a high renewable energy (20%), high
EE (2% by 2020) and DR at 5.8% of peak demand by 2023, despite Staff’s request that the
company do so. According to Mr. Harlow, such a model run could demonstrate that the proposed
NGCC could be reduced in size or could be delayed economically. Mr. Harlow also suggested
that the 2 MW and larger renewable projects in DTE Electric’s interconnection queue could be
used to increase the company’s renewable portfolio at the company’s avoided cost.
Ms. Simpson agreed that DTE Electric modeled a range of potential scenarios but she
expressed concerns about the modeled size of some of the resources, which resulted in renewables
and demand side resources treated unequally to conventional generation. According to
Ms. Simpson:
[I]n some instances resource expansion models can be influenced by the specified
size of the new resources available for the model to select. For instance, smaller
resources are less expensive but if there are not enough of them to fill the entire
need, the model will select the larger, more expensive resource instead. Models do
not typically overbuild unless they are forced to do so by the user. In this instance,
the model may select the single large option that fills the entire need because the
user did not offer enough smaller options to allow the model to diversify. If the
model cannot solve the expansion plan using the limited number of smaller options,
then it is forced to select the larger resource option as being the most economical.
***
One way to avoid such a situation is to model a generic combined cycle and a
generic combustion turbine as smaller increments but allow the model to build
multiple units in one year. This method allows for clear visibility around the actual
amount of energy and capacity needed from larger generation options while still
including any of the less expensive but smaller demand side options and additional

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 renewable energy options that may be cost effective. In short, this method allows
new resources to be selected on an equitable basis.
5 Tr 210. Ms. Simpson further observed:
It is true that the Company’s proposed larger single natural gas generation resource
would have an advantage of economies of scale resulting in a lower per megawatt
cost as compared to the same technology in a smaller size. However, without
running a scenario with the energy efficiency, demand response, and renewable
energy resources as Staff has indicated and utilizing the generic resource method
discussed above, the total cost of all resources combined is unknown.
5 Tr 211.
With respect to the company’s risk analysis, Ms. Simpson explained that DTE Electric
evaluated four very different build plans, all containing the proposed project. According to
Ms. Simpson, three of these plans “were not optimized generation plans or even near optimized
expansion plans or any scenario in the Company’s IRP. It is not clear exactly what the Company
expected to determine from such a risk assessment.” 5 Tr 213.
Mr. Evans testified “that DTE has not supported its application for approval of the new NGCC
generation facility with the required analyses. Specifically, DTE has not accurately projected or
analyzed resources, capacity and load requirements, and costs under its proposed portfolio.” 5 Tr
322. Mr. Evans testified that in his modeling, he identified scenarios that could defer, displace, or
partially displace DTE Electric’s proposed plant until 2029, with a savings of $1.88 billion in net
present value of revenue requirement (NPVRR) compared to the company’s preferred plan. Id.
Mr. Evans described the Strategist model as follows:
Strategist is a resource planning software model used to develop resource plans for
electric utilities. Given projections of future load growth, fuel prices, the costs of
potential new resources and other information, Strategist selects a resource plan that
minimizes ratepayer costs while maintaining reliable service. Strategist proceeds
one year at a time, simulating hourly dispatch while tracking generation and system
costs. Strategist produces a schedule of various combinations of new resource
additions, which may include natural gas combined cycle plants, combustion
turbines, renewable resources, peak load reduction programs, and energy efficiency
programs. Strategist tracks the cost for each combination, and at the end of the
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 model run, identifies the least cost expansion plan as well as sub-optimal plans
evaluated during the simulation. Thus, Strategist allows for the consideration,
testing, and comparison of various scenarios under different sensitivities (e.g.,
future fuel prices).
5 Tr 323. Mr. Evans testified that the first step in his analysis was to recreate the model exactly as
DTE Electric did, using the same inputs and assumptions in order to replicate the company’s
output. In this step, Mr. Evans reported that he found discrepancies between what the company
reported as the modeling output in testimony and in the company’s IRP for most of the Strategist
runs. 5 Tr 324. Mr. Evans explained that Strategist produces a range of plans, from most to least
optimal, it appeared that DTE Electric manually chose a non-optimal plan in many of its runs. For
example, Mr. Evans pointed out that for its 2% EE plan, the company chose the 22nd ranked plan
rather than a plan that ranked higher. 5 Tr 324-325. Mr. Evans explained that once he received
information from the company about which plans had been selected, he was able to “benchmark”
DTE Electric’s Strategist results. 5 Tr 326.
Mr. Evans stated that the significance of DTE Electric’s choice to select sub-optimal plans
means that some resource scenarios are not necessarily the least-cost plan. “Moreover, the
comparisons DTE made among the various Strategist cases inappropriately compare the least cost
plan for one case to plans that are, in many cases, not the least-cost plan, and thus are meaningless
comparisons.” 5 TR 327. For example, “DTE chose . . . the second-best plan for its Base
Resource case, the second-best plan for its Preferred case (the 1.5% Energy Efficiency case), and
the twenty-second-best plan for its 2.0% Energy Efficiency case. The resulting comparisons
between different cases and scenarios are skewed by this manual selection of non-optimal plans.”
Id. Mr. Evans stated that he corrected DTE Electric’s inaccurate comparisons and found that there
are more savings from the optimal 2% EE plan than the 1.5% EE plan that the company favors.
Id.
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 Mr. Evans acknowledged that “[o]nce a utility has identified and reviewed all optimal model
results and sensitivities, an evaluation of whether other considerations (such as minimizing risk)
justify selecting a plan that is not least-cost may occur.” However, Mr. Evans testified that DTE
Electric failed to disclose what other considerations led the company to select and compare nonoptimal plans. 5 Tr 328.
Mr. Evans listed several input errors that he found in DTE Electric’s modeling, including
(1) failure to include additional DR until after 2023, thereby keeping additional DR from
competing with the proposed project; (2) incorrect modeling of EE programs, which assumed that
EE savings will only last 15 years; (3) incorrect capacity credit for solar resources, which assumed
only a 41% on-peak capacity credit; (4) failure to consider and add incremental amounts of
renewable energy, wherein DTE Electric’s modeling only allowed the selection of 502 MW
increments of solar and 1,000 MW increments of wind; and (5) incorrect costs for wind and solar
resources. 5 Tr 329-335. In addition, Mr. Evans testified that he removed O&M from solar and
wind capital costs. 5 Tr 336. Mr. Evans presented Exhibit MEC-12, Case MEC 0, which
Mr. Evans testified corrected the errors in DTE Electric’s 1.5% EE run, resulting in a delay in the
plant until 2029 with a savings of $1.882 billion NPVRR.
Mr. Evans testified that DTE Electric’s 2017 Reference Case update also contained errors
concerning the heat rate of the proposed NGCC and the Belle River peakers, resulting in a
significantly understated cost for the proposed plant. 5 Tr 336-337. Mr. Evans testified that based
on corrections to DTE Electric’s inputs and assumptions and inputs from other witnesses to the
case, he undertook several additional Strategist model runs. Mr. Evans presented Table 1 in his
testimony, which demonstrates the results of 11 model runs. 5 Tr 340-342. Mr. Evans also
described the inputs and adjustments made in each of the runs. Id. Mr. Evans concluded that:

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 Strategist runs based on DTE’s modeling but correcting DTE’s flaws and properly
considering all resources show that DTE has more cost-effective options available
to meet the identified need for capacity in 2022. In fact, correcting these DTE
Strategist flaws delays the need for DTE’s proposed NGCC plant until 2029 and
results in $1.882 billion (NPV) in cost savings. In addition, further Strategist
modeling shows that there are many scenarios that would also delay the need for
the proposed NGCC plant and provide significant savings to ratepayers, compared
to DTE’s proposed 1,100 NGCC generating facility in 2022.
5 Tr 343.
Mr. Evans filed supplemental testimony addressing errors that DTE Electric acknowledged
making in the Strategist runs for the 2017 Reference Case that was submitted with the company’s
application. 5 Tr 346, Exhibit MEC-109, MEC-110C and MEC-111C. Mr. Evans testified that
the company’s error in the heat rate of the plant increased the cost of the proposed NGCC and
decreased the generation of the plant. 5 Tr 347-348. Despite correcting these errors, DTE Electric
made no adjustments to its proposed plan. 5 Tr 349.
In rebuttal, Mr. Chreston testified that the alternative analyses provided by Mr. Evans and
Mr. Beach “are based on a misrepresentation of modeling results that stem from failing to compare
DTE Electric’s Proposed Project on an equivalent basis.” 6 Tr 1777. Mr. Chreston explained that
Mr. Evans adjusted O&M costs for wind and solar so that they were not treated as capital costs.
However, the same adjustment was not made for the O&M costs for the proposed project, thus
making the project appear more expensive. In addition, Mr. Chreston testified that Mr. Evan’s
corrections were made to the 2017 Reference Case but included a generic NGCC as a resource
option rather than the proposed project. 6 Tr 1777-1778.
Mr. Chreston testified that using Mr. Evan’s Case 0 as a starting point, he revised the
treatment of O&M costs and introduced the proposed NGCC as an option. EE and DR levels were
not altered. Id. The results of Mr. Chreston’s re-analysis of Mr. Evans’ Case 0 showed, based on
different adjustments: (1) a generic 3x1 NGCC in 2023 at a cost (NPVRR) that is $44 million
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 more than Mr. Evan’s Case 0; (2) a generic NGCC in 2023 at an NPVRR that is $78 million less
than Mr. Evans’ Case 0; (3) the proposed plant in 2023 at a cost (NPVRR) that is $545 million less
than Mr. Evans’ Case 0. 6 Tr 1779-1780.
Mr. Chreston testified that the reason the plant is moved to 2023 is because he did not modify
the EE assumptions by Mr. Neme “the result of which incorrectly moves the need for capacity to
2023.” 6 Tr 1780. Mr. Chreston also explained that the heat rate errors that Mr. Evans cited in his
supplemental testimony do not affect the outcome of the modeling, noting that the majority of the
scenarios and sensitivities assumed the correct heat rate. The two modeling runs where incorrect
heat rates were used were rerun with correct inputs, and the result, a 1,100 MW NGCC in 2022,
was the same. 6 Tr 1782.
Mr. Chreston disputed Mr. Evans’ claim that the heat rate error calls into question DTE
Electric’s entire analysis, reiterating that the company’s case included 60 different model runs,
only two of which contained errors in heat rate. 6 Tr 1783. In addition, Mr. Chreston disputed
that the company failed to detect a $500 million error, explaining that changes in NPVRR only
“come into play when comparing that run against a sensitivity. However, the 2017 IRP reference
case Strategist run did not compare the total net present value of that plan against another
sensitivity.” 6 Tr 1784.
With respect to Mr. Evans’ claim that MEC/NRDC/SC’s preferred case, Case 0, results in a
$1.88 billion NPVRR cost savings, Mr. Chreston testified that Mr. Evans “draws his conclusion by
making a flawed comparison between his Case 0 and DTE Electric’s 2016 1.5% EE case.” 6 Tr
1785. Mr. Chreston explained:
Case 0 that is being proposed as the recommended course of action by Witness
Evans is modeled on a different basis than DTE Electric’s 2016 1.5% EE case.
MEC Witness Mr. Neme further claims that “DTE significantly overstates the
amount of future efficiency program savings embedded in its load forecast” (Neme
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 testimony, p 7), and makes an adjustment to MEC’s Case 0 to account for this
assumption. This adjustment lowers the load forecast. However, Company
Witness Mr. Leuker thoroughly refutes the appropriateness of Witness Neme’s
proposed adjustment. Nevertheless, even if one were to accept Witness Neme’s
adjustment just for the sake of this comparison, then Witness Neme’s load
adjustment should also be applied to the 2016 1.5[%] EE sensitivity to place the
comparison on the same basis. The inappropriateness of MEC’s comparison of
their Case 0 to DTE Electric’s 2016 1.5% EE case can be demonstrated by
comparing two of DTE Electric’s scenarios that used different load assumptions.
An example of a similar comparison that uses different load assumptions would be
a comparison of the IRP 2016 Reference case against the Low Load sensitivity,
which results in a $2 billion NPV difference between plans[.]
6 Tr 1785. In addition to the load forecast used in Mr. Evans’ Case 0, Mr. Chreston also disagreed
with the assumptions for EE, DR, renewable energy, and plant cost that were incorporated in that
model run. However, he reiterated that even without correcting these assumptions, the company’s
proposed project was the most economical. 6 Tr 1786-1787, Exhibit A-77. Mr. Chreston
highlighted Case 0_B_DTE in Exhibit A-77, explaining that this sensitivity was based on
Mr. Evans’ Case 0 with corrected heat rates as pointed out in Mr. Evans’ supplemental testimony,
as well as the O&M adjustments to the proposed project recommended by Mr. Allison. “This
optimization results in a plan that includes the Proposed Project in 2023 and is $545 million
cheaper than Witness Evan’s Case 0.” 6 Tr 1788.
Discussion
As is obvious from the discussion of the record above, integrated resource planning requires
myriad assumptions. The Commission believes there is great value to have MEC/NRDC/SC’s
modeling results to consider as part of this case. The large swings between Mr. Evans’ Case 0,
which adjusted DTE Electric’s Reference Case, and DTE Electric’s adjustments in response to
those adjustments demonstrate that changing even one assumption can alter results in a significant
fashion, and it underscores the need for additional transparency in modeling. Nonetheless, the
Commission finds that the validity of MEC’s claimed $1.8 billion savings was rebutted by DTE
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 Electric, and that no party refuted DTE’s findings at later points in this case (during cross
examination, in briefs, or in reply briefs) and as a result, the Commission is unable to rely on this
claimed savings estimate when making decisions in this case.
The Commission agrees with the Staff, and several intervenors, that DTE Electric should have
provided more detail in its modeling and screening concerning how the company developed
optimal EE, renewables, and DR levels in its IRP. Modeling by both Mr. Evans and Mr. Chreston
shows that achieving 2% annual energy savings could defer the proposed plant by one year, to
2023. 6 Tr 1787-1788, Exhibit A-8. An investment in energy efficiency at this level, if feasible,
would also provide flexibility and mitigate risks in the event coal plant retirements occur earlier
than planned, or the gas plant construction is delayed either intentionally due to potential cost
savings from a later in-service date or unintentionally due to permitting or construction challenges.
Moreover, combining incremental EE with other options that can be scaled up over time, such as
DR and renewable energy, would provide a diverse resource portfolio that could displace the
second gas plant in the late 2020s.
Nevertheless, the 2% savings level does not displace the proposed gas plant, it only defers it
by one year. And the Commission has some reservations about the ability to scale up and sustain
2% annual energy savings. First, the company has only recently updated its plan to achieve
overall EE savings of 1.5%. This represents a significant increase above the company’s prior
1.15% EE savings per year, and, although the plan contains programs designed to achieve 1.5%
EE savings, there is no way to know at this early stage of the plan whether the planned savings
will in fact materialize. The Commission has made adjustments to refine and increase the rigor of
EM&V approaches and tools to verify savings for compliance and to determine financial
incentives. This could make it more challenging for utilities to achieve and sustain a 2% annual

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 savings level over an extended period. Further, the Commission is persuaded by the company’s
testimony that very few utilities have actually met, let alone exceeded, an EE savings objective of
2%. Finally, there is beginning to be some indications that despite how popular or successful
residential EE programs are, other factors are at work that may be offsetting those energy
efficiency savings, whether through the purchase of more electrical products or more use of energy
efficient products, simply because they are energy efficient. Even though DTE Electric and other
utilities have been consistently achieving 1% savings or higher under existing EE programs since
the 2008 law, corresponding reductions in actual sales are not occurring. Accordingly, the
Commission has in recent rate cases called for staff to examine further load forecasting
methodologies and the relationship to EE. See, e.g., March 31, 2018 order in Case No. U-18322,
p. 50 and April 18, 2018 order in Case No. 18255, p. 36.
Turning to DR, the Commission finds DTE Electric’s plan to add only 125 MW of
incremental DR to its current portfolio is overly conservative given the results of two potential
studies. But again, the Commission is reluctant to assume that, given the company’s limited
experience with new DR program marketing and deployment outside of small-scale pilots and the
uncertainty surrounding customer receptivity to TOU rates, DTE Electric could effectively ramp
up its DR program to the levels necessary to offset a significant amount of capacity the company
will require in 2022 and 2023. Residential customer adoption of TOU rates represents a
significant amount of the near-term DR identified in the statewide potential study. The
Commission finds it is necessary to further test the marketing of TOU rates given the limited
participation to date, as well as customer interest in and response to TOU rates, including
persistence of demand savings under this rate design/DR option.

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 In order to reduce barriers to market-based demand response and in anticipation of evolving
FERC policy, the Commission is considering removing the current ban on third parties enrolling
regulated utilities’ bundled customers in non-utility demand response programs and bidding that
resource into the wholesale market. See, March 29, 2016 order in Case No. U-16020. The
Commission is monitoring FERC proceedings as FERC revisits, and perhaps limits, its policy with
respect to states’ ability to ban DR aggregation. Accordingly, the Commission directs the DR
Workgroup to begin to evaluate coordination and communication issues among aggregators,
customers, the Commission, utilities, and MISO, that may need to be addressed if third party DR
aggregation is permitted in the future. The DR Workgroup may want to consider models in other
states, such as Indiana.
The Commission does not anticipate significant growth in DR through aggregation due to
MISO’s wholesale market design with depressed capacity prices. Thus, such a policy change on
aggregation is highly unlikely to alter the need for the proposed gas plant but the Commission is
interested in removing regulatory barriers in the event market conditions change.
In addition, to facilitate the ability of customers to utilize technologies and work with third
parties to manage their energy use and costs, the Staff should engage with DTE Electric in the
ongoing data access tariff update proceeding, in Case No. U-18485 to ensure that utilities provide
timely access to consumption data in a usable format so customers can work with third parties to
manage their energy use and costs in conformance with Commission’s recently updated billing
rules.
Ultimately, the Commission finds that a narrow window exists prior to the planned coal plant
retirements that may not allow sufficient time for ramping up significant quantities of renewable
energy, EE, DR, storage, or other options in order to completely displace the need for the proposed

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 gas plant. Even if such options were feasible as a comprehensive portfolio to replace the gas plant
under this timeframe, the cost is higher. 6 Tr 1788. And as discussed above, without replacement
generation, there are potential operational reliability issues that could arise given the significant
amount of generation retiring in a concentrated area. Generators provide voltage support and other
ancillary services that support the transmission system. There is no dispute among the parties that,
due to the coal plant retirements, there is additional need for capacity in the early 2020s even with
the construction and operation of the proposed gas plant. DTE Electric has identified EE,
renewable energy and market purchases to fill this near-term, relatively modest need of
approximately 300 MW. In addition, the record shows that these resources, particularly increased
DR, EE and renewable energy, could potentially displace—not just defer—the second gas plant
identified in the company’s IRP for 2029.
DTE Electric has not committed to a specific strategy to fill this near-term capacity need or
the more significant, longer-term need over this 10-year horizon. Given potential changes in
customer demand, technology costs, and other factors, the Commission would expect these
resource plans and commitments to continue to evolve over time and adapt to changing conditions.
Modeling results presented in this case showed potential customer savings by augmenting the
proposed gas plant with incremental EE. When considering long-term needs and risks, the gas
plant combined with incremental EE appears to be the most reasonable and prudent option
assuming that energy efficiency in the range of 1.5-2% is feasible. Unlike the new IRP process,
the CON is not set up to review and approve a portfolio approach such as the proposed plant
combined with energy efficiency and other resources. Some parties suggested the Commission
deny the CON and have DTE Electric re-file under the new IRP guidelines. In addition to the legal
considerations with such approach, the Commission is concerned that the delay could create

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 regulatory uncertainty that is reflected in future bids, thereby raising costs, and there is a need to
proceed with construction in 2019 to ensure reliability as coal plants are retired.
Nevertheless, as these options and decisions about resource plans to complement the gas plant
continue to be explored, the Commission wants to avoid a situation in which low-risk, costeffective options such as EE and DR, which need time to scale up and that depend on voluntary
customer participation, are limited or foreclosed from meeting a longer term need due to a lack of
timely commitment by the utility.
Accordingly, the Commission finds that sufficient time exists for the company to develop and
analyze a cleaner alternative portfolio in place of the second natural gas-fired plant identified by
the IRP to fill a capacity need in 2029. The Commission looks forward to addressing these issues
in detail in the company’s 2019 IRP filing, and benefitting from additional analysis and dialogue
with stakeholders on how these options can ensure a balanced, reliable, and adaptable portfolio in
the near and long term. To ensure that the Commission can properly evaluate all options, the
Commission directs DTE to file in its 2019 IRP application under Section 6t, an additional
scenario that shows a portfolio consisting of EE, renewable energy, DR, storage, and other nonfossil fuel options, ramping up over the years preceding 2029, resulting in a cleaner alternative
2029 portfolio, that could augment the proposed 2022 NGCC and accommodate the retirement of
Belle River, without the need for an additional gas plant. This scenario would be in addition to the
optimal portfolios presented by the Company based on the scenarios adopted by the Commission
in the November 21 and December 20 orders. Should the Company find that the timing of the
2029 capacity need has shifted to some later point in the future, in the company’s next IRP, DTE
Electric is still directed to develop and analyze a similar cleaner alternative portfolio to be

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 presented alongside any other optimal portfolios that may be developed in the Company’s next
IRP.
DTE Electric is also expected to outline the associated timing, procurement strategies, and
programmatic approaches to scale up these resources to meet this need in a cost-effective, reliable
manner. DTE Electric, the Commission, and stakeholders would be well served by the company’s
coordination with the Staff and other interested parties in the development of such scenario before
the IRP is filed. And to be clear, in determining the IRP in the instant proceeding complies with
law, the Commission is in no way endorsing or determining the reasonableness of a second gas
plant or even any planning activities by DTE Electric to pursue such a plant. In fact, there is
compelling evidence to suggest that a second plant could be avoided.
While these resource planning decisions will be addressed in the 2019 IRP, the Commission
also expects to closely examine in other Commission proceedings (i.e., rate cases, PSCR cases,
and renewable energy and energy waste reduction plan cases, as applicable) DTE’s purchases and
other actions to arrange energy and capacity going forward, particularly the prudency of costs that
could be avoided or mitigated if more cost-effective resources are available.
c. Alternative Purchase of a Facility or Power Purchase Agreement
The CON and IRP guidelines do not have requirements for bidding of alternatives such as a
PPA or plant purchase. Ms. Dimitry testified that in March 2017, DTE Electric issued an RFP for
both natural gas fueled generating assets and PPAs that could address short-term capacity deficits
as an alternative to the gas plant proposed to be owned and operated by DTE Electric. 6 Tr 1614.
Ms. Dimitry stated that conforming bids were required to meet the following specifications:
(1) combined or simple-cycle NGCC technology; (2) must qualify for MISO capacity credit by the
2022 planning year; (3) unforced capacity (UCAP) between 225 and 1,100 MW; (4) must be

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 located in LRZ 7; and (5) maximum PPA length of seven years beginning June 1 of any year
between 2018 and 2022. Id.
Ms. Dimitry testified that the company requested bids on PPAs up to seven years “to gain
insight on short term capacity options” and to “provide[] a bridge to the expected timeframe for
the next round of coal plant retirements for the Company, which will trigger a new assessment of
energy and capacity needs and possible solutions.” 6 Tr 1615.
Ms. Dimitry opined that DTE Electric’s bid requirements were reasonable for any third-party
considering building generation or offering a PPA. According to her, a project could be completed
by 2022, the locational requirement reflects resource adequacy rules, and merchant generators are
able to obtain financing without long-term contracts. In addition, Ms. Dimitry testified that “[t]he
Company also believes that a shorter PPA term minimizes the risks of misaligned incentives
between the Company and a PPA supplier[,]” further explaining that additional risks of long-term
contracts include: (1) risk that the counter-party will fail to perform; (2) risk of contract
termination; (3) reduced operational flexibility; (4) change of ownership of the generating facility;
and (5) balance sheet impacts because financial markets view long-term contracts as liabilities.
6 Tr 1616-1617.
Ms. Dimitry testified that DTE Electric received three bids in response to the RFP, one of
which did not conform to the size requirement. One bid, offering a 1,100 MW unit was evaluated
and was found to have a higher NPVRR than the proposed project. 6 Tr 1619, Exhibit A-2.
Ms. Dimitry indicated, however, that the company is still considering the bids in the event the
company requires some incremental capacity as plants retire. 6 Tr 1620.
Mr. Olling testified that the MCV did not participate in the competitive bid process because
DTE Electric would not consider a PPA longer than seven years, despite the company’s proposal

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 to build a plant with an operating life of 30 years or more. Specifically, Mr. Olling testified that in
response to DTE Electric’s RFP, the MCV sent a letter requesting additional information
necessary to develop different PPA options. 5 Tr 610, Exhibit MCV-1. According to Mr. Olling,
DTE Electric responded by indicating that a long-term PPA would not be comparable to a selfbuild option and failing to provide any answers to the MCV’s request for additional information.
5 Tr 611, Exhibit MCV-2. Mr. Olling stated that because DTE Electric refused to consider any
PPA term beyond seven years, the MCV determined that it would be fruitless to respond to the
company’s RFP. Contending that DTE Electric failed to comply with the requirements of Section
6s, Mr. Olling posited:
By categorically ruling out a long-term PPA commencing with the anticipated inservice date for the Company’s self-build option, the Company foreclosed
competitive proposals from merchant generators such as MCV that would require a
similar lead-time to obtain permits, complete construction, and achieve commercial
operation for new generating facilities. The Company thereby established RFP
criteria that could not produce comparable alternatives to its preferred self-build
approach.
5 Tr 613.
In response to Ms. Dimitry’s claims about the risks associated with long-term PPAs,
Mr. Olling points out that “company ownership . . . does not alleviate performance risk” further
noting that DTE Electric failed to address the risk to its customers in the event the proposed
project becomes obsolete before the end of its useful life. 5 Tr 618. Mr. Olling stresses that the
remaining risks cited by Ms. Dimitry can be addressed through contract negotiations. With respect
to balance sheet risk, Mr. Olling opined that such risk:
. . . is shorthand for stating that the Company believes its shareholders would be
better off by building a plant that can be included in rate base and upon which it can
earn a return than they would be if the Company enters into a long-term power
purchase agreement. Ms. Dimitry does not claim to have any financial experience
with public utility credit ratings or the metrics that ratings agencies apply. She does
not discuss the balance sheet implications of the Company’s self-build option, or
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 the fact that financing the roughly $1 billion cost to construct a 1,100 MW power
plant would likely involve issuances of both debt and equity by the Company.
5 Tr 620. Mr. Olling continued, citing specific risks associated with the self-build option
including construction cost overruns, plant performance, lack of adaptability under utility
ownership, and permanent loss of the asset. Mr. Olling testified that DTE Electric did not account
for these risks in its IRP. 5 Tr 621.
Mr. DiDomenico questioned why DTE Electric’s RFP resulted in few bids:
An 1,100 MW facility with an initially estimated cost of $989 million is a
significant investment opportunity, and it is very reasonable to expect that far more
qualifying bids would have been received. The lack of a robust market response to
meet an 1,100 MW generating station need requires a very close examination of the
RFP requirements and overall process to determine whether the scarcity of
qualifying bids simply reflects competitive market conditions or whether some
peculiarities related to the RFP chilled the market for alternatives in this case.
6 Tr 1568. He opined that DTE Electric’s decision to restrict bids to resources located in LRZ 7,
coupled with the seven-year PPA term, likely limited the response to the RFP, like Mr. Olling,
noting the inconsistency between the short PPA length and the 30-year operating life of the
proposed project. Mr. DiDomenico concluded that, “the Commission has ample grounds to
seriously question the competitiveness of the market testing of the alternatives to the Self Build
option,” 6 Tr 1569. Accordingly, he made the following recommendations for future solicitations:
I recommend that the Commission require that proposed resource RFPs be
submitted at least 90 days in advance of issuance with an opportunity for
stakeholders to provide comments on the proposed form, ground rules, timeline and
other requirements of the RFP. The Commission could then consider these
concerns before approving an RFP for a company to issue. Review and approval of
an RFP in advance of issuance would enhance openness, fairness and transparency
of the process, and should result in a more robust and competitive market response.
Id.

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 Ms. Simpson also testified that while the Staff acknowledged there is some risk to a long-term
PPA, the company’s proposed project also entails risk. Ms. Simpson indicated that PPA
shortcomings could largely be addressed by careful contracting. 5 Tr 200.
Although the Commission’s CON and IRP guidance does not include a requirement to
conduct competitive bidding as an alternative to the proposed project, or details on how such
bidding should be conducted, the Commission views competitive bidding as a standard business
practice to ensure cost-effectiveness. It is integral to determining whether the proposed course of
action is the most reasonable and prudent option by testing market response to alternatives.
The Commission has significant concerns with DTE Electric’s RFP and bidding process
particularly for a PPA option. The Commission agrees with the Attorney General that, given the
size and expense of the proposed project, one would have expected a more robust market response
to the solicitation. The Commission also believes that although there may have been opportunities
to enter into a PPA, DTE Electric’s insistence that any PPA be limited to seven years may have
dampened potential responses. But, as DTE Electric, the Staff, and the Attorney General point
out, under Section 6s(13), an existing supplier that meets the qualifications under that subsection
may submit a proposal directly to the Commission; however, no alternative proposals were
presented. Moreover, the Commission has not established guidelines or processes for Commission
review of RFPs or bid evaluation (outside of renewable energy program) and DTE Electric
provided a reasonable explanation for including certain constraints in the RFPs due to various
risks. As Ms. Dimitry explained, “the financial exposure to the Company and its customers in the
event of a counterparty default for a PPA of this magnitude could be significant. . . . In this
instance, the Company and its ratepayers are at a significant risk if the level of financial remedy

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 within the contract does not match the Company’s penalties, or if the Company is unable to collect
from the counterparty.” 6 Tr 1627.
In light of Commission’s findings on this issue, and the importance of ensuring confidence by
third parties in the integrity of any RFP processes in the future, the Commission adopts in part the
Attorney General’s recommendation that the Commission provide more oversight of future RFPs
that may be used to support a CON or IRP. Specifically, the Commission agrees that any
proposed RFP should be submitted to the Commission at least 90 days before issuance for review
by the Staff. As the energy industry continues to evolve and new technology solutions emerge,
including solutions that may involve greater engagement of end-use customers or integration with
the transmission or distribution system, it is also important to ensure that RFPs are truly open to
allow a broad range of potential solutions to be considered. While this will make the bid
evaluation process more complicated, it can avoid RFPs inadvertently placing barriers on options
such as energy storage that could provide multiple values or attributes.
The Commission expects competitive bidding to be of increasing importance for the selection
of resources and the approved amounts under the pre-approval provisions of CONs and IRPs.
Accordingly, the Commission directs Staff to research approaches and best practices for RFP and
competitive bidding in other jurisdictions.
7. Electric transmission options for the electric utility.
In his initial brief, the Attorney General explained that, with respect to resource adequacy
requirements:
When sufficient transmission import capability is not available, [load serving
entities] LSEs within a transmission import-limited LRZ may be forced to rely
more on capacity located inside the LSE’s zone even though lower cost resources
may be available outside the zone. Besides the system wide PRMR, MISO
produces a LRZ specific PRMR which must be met by the LSEs within the zone.
All the LSEs and utilities within the MISO region have the flexibility to meet their
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 respective PRMR by using a combination of self-supply, bilateral contracting, and
residual procurements through MISO’s centralized Planning Resource Auctions
(“PRAs”). Besides the system wide and LRZ specific PRMR, MISO produces
every year LRZ specific parameters.
MISO is obligated to calculate the following LRZ specific parameters
on an annual basis : (i) Local Reliability Requirement (“LRR”), (ii) Capacity
Export Limit (“CEL”), (iii) Capacity Import Limit (“CIL”) and (iv) Local Clearing
Requirement (“LCR”). The LRR represents the amount of resources needed by a
LRZ to reliably meet its forecasted peak load without the benefit of imported
capacity. CIL and CEL provide the maximum amount of capacity that can be
imported –CIL –or exported –CEL-from a LRZ after respecting the established
MISO reliability standards. LCR is the LRR reduced by CIL (LCR = LRR –CIL).
These four parameters define system constraints and are used by MISO during the
PRA in a way that capacity is procured in the most cost-efficient way while
respecting resource adequacy and transmission reliability standards.
Attorney General’s initial brief, pp. 8-9.
Mr. Weber testified that import capability into DTE Electric’s service territory is currently
constrained due to the loss of the major east-west 345 kilovolt (kV) lines into that territory.
Mr. Weber indicated that he had reviewed the MISO transmission expansion plan for 2014
(MTEP-14) considering any projects with an in-service date of 2025. According to Mr. Weber,
“no approved projects existed that would expand firm import capacity.” 7 Tr 2171.
Mr. Osborn testified that DTE Electric has access to three electric markets: MISO, PJM, and
Ontario. Mr. Osborn noted that the connection between MISO Zone 7 and MISO Zone 6 is fairly
narrow and consists of a 345 kV MISO transmission line and several 345 kW transmission lines
from PJM. 5 Tr 508. Currently, according to Mr. Osborn, there is an underutilization of imports
from PJM to Zone 7, which results in higher costs for Michigan customers. Mr. Osborn opined
that this was the result of Michigan utilities focusing more on in-state generation rather than on
interconnection with the rest of the grid. 5 Tr 514. Mr. Osborn further observed that PJM has
significant excess capacity for 2023 through 2029. Exhibit MEC-76. Thus, Mr. Osborn testified

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 that lower-cost imports from PJM could defer or replace DTE Electric’s proposed project. 5 Tr
514-515.
Mr. Osborn testified that in addition to the possibilities presented by the PJM market, Zone 7
is also interconnected with the Ontario independent system operator (IESO). According to
Mr. Osborn:
A recent MISO analysis found a Total Transfer Capability from IESO to MISO
Central of 2,487 MW, more than double the capacity proposed in the CON.
Ontario also appears to have energy that is not used by markets: IESO makes
ongoing short-term projections of resource adequacy that report thousands of MW
of excess capacity and thousands of MWh of excess energy.
5 Tr 517. Mr. Osborn further observed that Ontario prices are typically lower than Michigan’s,
concluding that it would be reasonable and prudent to evaluate imports from Ontario as an
alternative to the proposed project.
In addition to the possibility of imports from Ontario, Mr. Osborn testified that that IESO is
interconnected with Hydro Quebec, a winter-peaking utility with approximately 6,000 MW of
excess summer capacity that can be exported. DTE Electric, on the other hand, has approximately
4,000 MW of excess winter capacity, raising the potential for power exchanges between DTE
Electric and Hydro Quebec. 5 Tr 519.
Mr. Osborn disagreed with Mr. Weber’s claim that the transmission into Michigan is currently
constrained, contending that “Mr. Weber was not relying on current information about the state of
the system.” 5 Tr 520. Mr. Osborn observed that the constraint to which Mr. Weber was referring
has been addressed, and “the 2017 MTEP Book 2 now list the Capacity Import Limit constraint for
Zone 7 as being south of Detroit rather than on the east-west 345 kV line.” 5 Tr 522, Exhibit
MEC-84. With respect to the constraint south of Detroit, Mr. Osborn testified:
Exhibit MEC-85 is a presentation from the December 6, 2017 1st East Subregional
Planning Meeting for the MTEP18. Pages 10-11 of the presentation list two
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 projects to address this transmission constraint. The projects are potential upgrades
to the 345kV station equipment at Brownstown and Monroe, and at Monroe and
Wayne. They have costs of $1.076 million and $580,000, respectively; and in service dates of 2020 and 2018, respectively. Further studies will determine if the
potential upgrades will be submitted for approval for construction.
5 Tr 523-524 (footnotes omitted). If additional import constraints develop in the future on the 345
kV east-west line, Mr. Osborn indicated that the retirement of the Palisades Nuclear Plant in 2022
may relieve these constraints. 5 Tr 524.
Mr. Osborn also disputed DTE Electric’s reliance on the MISO CIL as a reason that firm
transmission is not an option to defer or displace the proposed project. Mr. Osborn testified that
“[t]he CIL restricts general imports from other MISO zones, such as through capacity auction
purchases. It does not, however, apply to the import of power from a specific source or sources
outside of MISO.” 5 Tr 524-525. Mr. Osborn nevertheless acknowledged that if there were a
capacity constraint, it would still need to be addressed through a Transmission Service Request, “a
specific study, which DTE has apparently neither sought nor carried out.” 5 Tr 525. Mr. Osborn
explained that the CIL is a limitation on the amount of power that can be imported from one MISO
LRZ to an adjacent LRZ and is not an expression of transmission limitations. 5 Tr 525-526.
Mr. Osborn explained that transmission upgrades may not be necessary for DTE Electric to secure
firm import, however, DTE Electric never explored this option. 5 Tr 528.
Mr. Berkow sponsored a transmission study, set forth in Exhibit MEC-89, which showed that
the current transmission interface between Michigan and IESO is currently controlled by phase
angle regulators (PARs) at three substations. According to Mr. Berkow, “It is possible that the
PARs could change their operation to increase import capability of power from IESO into
Michigan; however, additional analysis by ITC (the owner of the PARs on the United States side)
and MISO would need to be performed to verify.” 5 Tr 548. Without the ITC and MISO

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 analyses, Mr. Berkow assumed a new high voltage direct current (HVDC) converter station could
be built, to import 1,500 MW of capacity from Ontario into Michigan. Mr. Berkow testified that
the cost of the HVDC converter station and transmission upgrades would be $320 million;
however, [i]f the PARs are able to be used to their rated capacity, and the Ontario system is able to
be dispatched to avoid the transmission upgrade, total cost would be just $15 million for the
Michigan transmission upgrades.” 5 Tr 549.
In rebuttal, Mr. Weber averred that DTE Electric undertook the required transmission studies
set forth in the IRP guidance. With respect to transmission options, Mr. Weber testified that “I
examined any projects with an in-service date of 2025 in the MTEP14 database and subsequent
MTEP projects in close proximity to the proposed project. The results of the analysis were that no
approved projects existed that would expand firm import capacity.” 7 Tr 2171. Mr. Weber also
pointed out that MEC/NRDC/SC failed to present any transmission alternatives that would
constitute a viable option. He added:
Any new transmission to relieve Michigan congestion or to increase import
capability would require a lengthy study conducted by MISO through their MTEP
and congestion study processes, and potentially the MISO-PJM Interregional
Process. Additionally, it is important to understand that DTE Electric is not a
transmission owner and does not possess the unilateral authority to compel MISO
to approve transmission modifications.
7 Tr 2172. Mr. Weber concluded that:
None of the high-level transmission modification ideas to address firm transmission
import constraints, presented in Witness Osborn’s testimony, have materialized into
project proposals in the MISO transmission planning process. As already stated,
DTE Electric does not possess the authority to unilaterally compel MISO to
approve such projects, and therefore cannot risk its statutory obligation to serve on
the uncertain outcome of the MISO stakeholder process and a decision from the
MISO Board of Directors. In addition, the project study process to address firm
transmission import constraints can be lengthy and uncertain, and the overall
timeframe from study to completion, typically several years as witnessed on similar
projects, would likely preclude them from consideration as a viable alternative to

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 the proposed project. It is also important to note that any transmission alternatives
would only work when a firm generation resource is available to import.
7 Tr 2173.
Ms. Wojtowicz responded to Mr. Osborn’s suggestion that DTE Electric could import
capacity from outside LRZ 7, testifying:
If the Company were to rely on capacity from outside of MISO LRZ 7 (from
another MISO LRZ or an adjacent RTO) to replace its retiring coal units, reliability
in LRZ 7 would likely not meet acceptable standards as there would likely not be
sufficient local capacity resources to meet the LCR. Based on recent MPSC Staff
projections in Case No. U-18444, LRZ 7 could be as short as 1,407 MW (Exhibit
A-55) to meeting the LCR after the retirement of DTE’s River Rouge Unit 3, St.
Clair Units 1, 2, 3, 6, & 7, and Trenton Channel Unit 9.
7 Tr 2248.
The Commission agrees with MEC/NRDC/SC and the Attorney General that DTE Electric’s
analysis of transmission options was unnecessarily weak. The Commission is especially
concerned that the company chose to rely on an MTEP report that was a year out-of-date at the
time of the company’s review. As Mr. Osborn pointed out, some of the transmission constraints
have been relieved, as a review of more recent MISO material would have shown. Nevertheless,
the Commission finds Ms. Wojtowicz’s and Mr. Weber’s rebuttal persuasive, that given the time
requirements for transmission studies and transmission build out, coupled with concerns about the
reliability of imported capacity, there is no reasonable and feasible transmission alternative to the
company’s proposed project.
The IRP filing requirements adopted by the Commission under Section 6s, state “to the extent
practicable, the IRP shall include analysis of existing transmission import and export capability,
proposed transmission projects, and the availability and economic impact of power imports and
exports.” December 23 order, Exhibit B, p. 4. DTE Electric technically met this requirement. In
the two prior CON cases, the Commission did not address in detail its expectations for
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 consideration of transmission alternatives. In Case No. U-18224, without any challenges from the
parties, the proposed plant was determined to be a lower-cost option to transmission upgrades that
had been previously identified by the transmission company as necessary absent a local generation
solution.
As DTE Electric points out, it has not been a transmission owner since it divested its
transmission assets in 2004. And although ITC was a party to this proceeding, neither ITC nor any
other transmission owner presented transmission options for Commission consideration. While
DTE Electric is not precluded from proposing transmission solutions through the MISO regional
transmission planning process, there are limits on the company’s ability to identify and pursue
transmission alternatives that other entities would need to build and own. Moreover, the import
constraints affecting import capacity for LRZ 7, and solutions to these constraints, are not
necessarily local, or even within the state, as shown in the MTEP 14, 15, and 16 reports.
Therefore, it is challenging for a non-transmission owning utility like DTE Electric to identify,
study, and implement transmission solutions, particularly to meet a near-term need. In addition,
there is inherent risk in siting and permitting transmission facility upgrades, particularly if they are
out-of-state with required siting and regulatory approvals and cost allocation.
Even though it is not a transmission owner, DTE Electric could have conducted a more indepth investigation of transmission system constraints as well as transmission options to enable
delivery of energy resources from outside of the MISO region by further engaging transmission
owners and other entities in a stakeholder process. As MEC/NRDC/SC pointed out, the company
relied primarily on existing approved transmission projects in the outdated MISO MTEP 14
Report. Mr. Osborn included references and exhibits in his testimony to more recent MISO loss os

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 load expectation (LOLE) reports and MISO MTEP 16 that clearly indicate different constraints
than those that existed in 2014. See, Exhibit MEC-84 and MEC-73.
Although Mr. Osborn and Mr. Berkow provide several transmission possibilities that may
allow for energy resources to flow into LRZ 7, those options are not coupled with any currently
qualifying external resources in MISO. According to Ms. Wojtowicz, external resources could
count toward the Zone 7 LCR to the extent that those resources are willing to comply with MISO’s
rules. 7 Tr 2264. Because there aren’t any existing, already qualified, external resources in MISO
that could potentially meet DTE Electric’s needs, coupled with the potentially changing MISO
rules surrounding external resources as evidenced in a recent FERC filing by MISO in
Case ER18-1173, significant risk surrounds the concept of relying on potential yet-to-be qualified
external resources to meet near-term capacity needs.
With DTE Electric’s planned coal plant retirements, and without the proposed 1,100 MW
NGCC plant or other alternative new planning resources counting toward the LCR in 2022 and
2023, Zone 7’s resource adequacy projections would be stark. Based on the Staff’s Report in Case
No. U-18441, and adjusting for the retirement of DTE Electric’s coal plants, Zone 7 would be at
risk of falling short of its LCR requirement by up to 716 zonal resource credits (ZRCs ). 13 Falling

13

The Staff’s March 6, 2018 Report and Recommendations in Case No. U-18441 shows an
LCR demonstrated position of 929 ZRCs for planning year 2021/22 for Zone 7. However,
subtracting 1215 ZRCs for the retirement of the St. Clair units results in negative 716 ZRCs. In
Case No. U-18444, Staff has indicated that concerns about Zone 7 not meeting the LCR are
diminished because of the Staff’s assumption that local utilities, due to inherent incentives to earn
a return on capital investments, will build new generation in the zone (and other options) to
replace retiring coal plants and the Palisades nuclear power plant when it is planned for closure in
the early 2020s. See Staff’s Initial Brief in U-18444, p. 14. If DTE Electric does not construct the
1,100 MW facility or otherwise ensure an equivalent amount of local planning resources in the
zone (or defer the plant retirements), the LCR outlook would be decidedly uncertain given the lack
of any public announcements to build generation in the zone.
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 below the LCR in the zone means that Michigan would not be meeting federal reliability
standards, and it increases the probability of an outage due to inadequate supply. The Commission
acknowledges that other local demand- and supply-side resources could help fill this gap without a
new gas plant but as discussed above, there is uncertainty with the ability to scale EE and DR to
the levels that would be needed in this timeframe, and uncertainty around the default and actual
capacity credit of other resources such as solar under MISO rules. In addition to the risk of not
meeting the LCR requirements in Zone 7, DTE Electric would likely fall significantly short of
meeting its required PRMR without replacing the retiring coal plants with other planning
resources. DTE Electric will indeed find itself in need of adding capacity resources to meet its
capacity demonstration requirements pursuant to Section 6w, as well as planning reserve margin
requirements at MISO.
There are also potential local operational reliability challenges associated with coal plant
retirements if there is inadequate local generation to provide voltage support and other reliability
support to the transmission grid. DTE Electric has submitted early requests to MISO to study any
reliability impacts associated with the retirement of the Tier 2 units. The results of these studies
were not available for inclusion in this record, but there are numerous instances in both the Upper
and Lower Peninsulas of Michigan in which coal plant retirements have required new generation
or transmission upgrades and/or delayed retirements to ensure near-term operational reliability
under different contingencies. It bears emphasizing that reliability and resiliency issues extend
beyond the counting of “ZRCs,” or capacity credit, under the MISO’s resource adequacy
requirements and the Commission’s implementation of section 6w in Act 341. Reliability is not
just about ensuring adequate capacity on the peak summer day. Local generation—unlike all the
alternatives presented in this proceeding—provides significant support to keep the grid operational

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 and stable on a minute-by-minute basis, year-round. Michigan’s generation fleet is undergoing a
significant transformation with approximately half of its coal fleet retiring over the course of about
a decade. The Palisades plant, which has been consistently operating nearly non-stop except
during re-fueling, is slated to close in early 2022. Consumers Energy is also considering four
additional coal unit retirements before 2025.
The Commission finds that this proposed gas plant, while quite large, fills only a fraction of
the power needs to be addressed by retiring plants representing thousands of megawatts in the
state. Moreover, unlike coal or nuclear or even older gas plants in the state, the proposed gas
plant’s expected 24/7 availability and ability to ramp output up and down quickly will better
position the utility and regional grid operators to integrate additional renewable energy such as
wind and solar. As Mr. Lucas pointed out:
DTE must maintain sufficient capacity to keep its system reliable. Flexibility – both
on the generation side and on the demand side – is key. As more variable resources
such as solar and wind are introduced, matching supply with demand will require
more attention. The ability for generators to respond quickly to changes in solar and
wind generation, and to ramp their output up or down, is critical. Additional
capacity resources and ancillary services capability from batteries, smart inverters,
and synthetic inertia can help smooth the changes in variable energy resources.
5 Tr 758. This plant provides greater flexibility as Michigan moves toward a more diverse
portfolio of resources with coal, nuclear, natural gas, wind, solar, biomass, expansions to pumped
energy storage, demand response, as well as a strong commitment—on the order of 50% beyond
statutory minimums—to energy efficiency.
The Commission encourages DTE Electric to continue to coordinate with MISO and ITC on
reliability planning to accommodate the retiring coal plants. In addition, in DTE Electric’s 2019
IRP, the Commission expects a far more robust analysis of transmission opportunities that might
defer, displace, or optimize the amount, type, and location of additional generation based on up-to-

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 date information about current and expected transmission system conditions and import/export
capabilities. To ensure alternatives are fully considered in future IRP proceedings, and the system
is optimized from a cost and reliability standpoint, the Commission also expects DTE to work
closely and collaboratively with ITC and other transmission owners to explore transmission
solutions and to work toward integrating the company’s distribution planning efforts with resource
planning.
After thoroughly considering alternatives, based on the Commission’s findings and
conclusions under MCL 460.6s(4), as set forth above, the Commission finds that DTE Electric’s
proposed project is the most reasonable and prudent means to meet the need for power in 2022.
Therefore, the CON requested under MCL 460.6s(3)(b) should be granted.
E. Will the construction of the new facility be completed using a workforce composed of residents
of this state?
DTE Electric provided substantial evidence that the construction of the new facility will be
completed using a workforce comprised of Michigan residents. Mr. Fahrer testified:
The total estimated craft labor workforce employed by the EPC Contractor for
constructing the Proposed Project is anticipated to involve in excess of 1.5 million
work hours with the demand for craft specialties shifting over the duration of the
project. Based upon a typical project schedule, the simultaneous craft labor
workforce is expected to peak around 520 full time equivalent (FTE) personnel
roughly19 months after the start of Construction. In addition to craft labor, EPC
on-site construction and management staff is estimated to include an additional 60
FTE[]s to support the construction project.
8 Tr 2614. In addition, Mr. Fahrer testified that there was adequate labor resources available in
the state, and he estimated that 90% of the craft labor force would consist of Michigan residents.
The Staff agreed with Mr. Fahrer’s estimates, and no other party took issue with DTE
Electric’s representations on this issue. The Commission therefore finds that the construction of
the new facility will be completed using a workforce composed of residents of this state.
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 F. Summary
In summary, as required by section 6s(4), the Commission thoroughly considered the need for
power; compliance with environmental laws; the reasonableness of the estimated cost of power;
whether the proposed plant is the most reasonable and prudent option to meet the need relative to
other resource options, such as energy efficiency, renewable energy, demand response, energy
storage, transmission, PPAs, and any alternative proposals submitted by third parties; and the local
workforce associated with the construction and investment in the proposed plant.
This application was examined under CON provisions in section 6s under Act 341, the CON
filings requirements updated in May 2017 to conform to revisions to 6s, and the IRP guidelines
approved by the Commission after section 6s was first enacted in 2008. Filing this CON under
these legal standards and regulatory guidance was not unexpected during the development of the
2016 energy laws and the revisions to the CON filing requirements adopted by the Commission,
with input from interested stakeholders, in May 2017. While the new IRP provisions and
Commission guidance under section 6t are more detailed and prescriptive, the Commission
benefitted from a robust record to make an informed decision under the applicable law in this
proceeding. As discussed in this order, deferring such decision to the 2019 IRP filing by DTE
Electric presents risks from a cost and reliability standpoint.
The modeling of options and analyses conducted by DTE Electric and the intervenors were
extensive and tested many combinations of options to inform this critical decision, particularly the
determination of whether the proposed gas plant is the most reasonable and prudent option. Over
70 modeling runs were presented. Given the importance of this decision, it is not surprising that
there was significant debate over competing IRP assumptions and methodologies—many of which
can have a major impact on the modeling results. While there is inherent risk with any decision of

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 this magnitude and the inquiries to examine alternatives could be nearly endless, particularly with
invariably changing assumptions and conditions affecting the energy industry, the preponderance
of evidence shows there is a significant near-term need for power and the proposed gas plant –
whether it goes into service in 2022 or 2023 – is the most reasonable and prudent option given the
standards set forth by section 6s, the Commission IRP and CON guidelines, and the alternatives
presented in this record. Aside from the modeling results, the Commission finds that there are
important feasibility and grid reliability questions that were not adequately addressed about the
near-term viability of various alternatives presented including transmission with imported power,
PPAs, and incremental renewable energy and demand-side options. The evidence also clearly
indicates that the costs for the plant, adjusted for Staff’s lower contingency amount, are
reasonable.
DTE Electric met the requirements set forth in section 6s and its applicable guidance for
CONs and IRPs for the three requested certificates under MCL 460.6s(3)(a),(b) and (d).
VI. OTHER ISSUES

A. Cost Recovery under MCL 460.6s(3)(d)
Ms. Uzenski testified in support of current recovery of financing costs related to the proposed
NGCC plant. Ms. Uzenski explained, that by “current recovery,” “I mean that in a general rate
case, the costs of construction work in progress [CWIP] for the proposed project, reflected in the
projected test year, would be included in rate base without an AFUDC offset. Construction costs
not included in rate base (due to regulatory lag) will accrue AFUDC until they are reflected in rate
base.” 5 Tr 1498. Ms. Uzenski testified that current recovery of financing costs, if approved,
would “reduce the total capitalized cost of the asset reflected in rate base, thereby reducing future
revenue requirements.” Id. However, traditional accounting and ratemaking for financing costs
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 would change the timing because financing costs would be accrued as allowance for funds used
during construction (AFUDC). AFUDC would then be recovered once the plant is included in rate
base. 5 Tr 1499.
Ms. Uzenski testified that there are approximately $400,000 in capital expenditures currently
in rate base incurred from 2011 through 2013 and that the company included $6.5 million of
capital expenditures and $26.6 million in CWIP, without an AFUDC offset, in the company’s
then-current rate case, Case No. U-18255. Id.
Mr. Nichols testified that the Staff supports the recovery of financing costs related to the
proposed NGCC, provided the costs are included in a general rate case and are found to be
reasonable and prudent. Mr. Nichols further testified that the Staff supports the company’s request
for traditional accounting and ratemaking treatment of financing costs in the event the
Commission does not approve current recovery of financing costs. 6 Tr 1579-1580.
No party opposed the company’s request for current recovery of financing costs for the
proposed plant, and the Commission finds that the request should be granted. Because the
Commission is granting CONs under Section 6s(3)(a) and (b), the Commission finds that the
capital costs of, and the financing plan for, the proposed electric generation facility, including, but
not limited to, the costs of siting and licensing a new facility and the estimated cost of power from
the new electric generation facility, will be recoverable in rates from DTE Electric’s customers.

B. Rate Impact Analysis
MEC/NRDC/SC contend that DTE Electric’s rate impact analysis was misleading, because the
analysis compared the cost of the proposed project to a no-build option that relies on expensive
market purchases. Further, they argue that the CON IRP guidelines do not indicate that the

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 analysis should be based on a comparison, let alone a comparison to a scenario that even DTE
Electric admits was not viable.
The Commission finds that DTE Electric’s purported rate impact analysis, as described by
Mr. Chreston and set forth in Exhibit A-10, could be misleading. The guidelines state: “The IRP
shall also present an estimated calculation of average customer rates as a result of the plan.”
December 23 order, Exhibit B, p. 7. While it is not necessarily unreasonable to compare rates to a
“no build option,” and the Commission’s IRP guidelines in another section call for a “no build”
analysis, it is important to be transparent about the actual rate impacts from the proposed plant.
The Commission is not required to make any findings with respect to customer rates under
Section 6s(4), but nevertheless finds that DTE Electric shall provide a straightforward analysis of
how customer rates are expected to change as a result of the Tier 2 unit retirements and the
addition of the NGCC plant over the first ten years of operation. The Commission is also
interested in understanding the impact to rates if some or all of the unrecovered book value
associated with the coal plant retirements were removed from rate base and addressed through
securitization or other financial measures, rather than recovery through traditional depreciation
schedules. While the Commission is not making a final determination on the unrecovered costs of
the retiring plants, it is nevertheless interested in the impact that different options may have on
customer rates.

C. NEXUS Pipeline
Mr. Beach and Mr. DiDomenico raised issues concerning the NEXUS pipeline. With respect
to increased risks and costs associated with the NEXUS pipeline, Mr. Beach testified:
[T]he new gas supplies from NEXUS may offset the upward pressure on the market
basis that could result from the incremental demand from new gas-fired generation
facilities such as the gas plant. However, the fact the DTE is likely to hold capacity
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 on NEXUS increases the risks that the gas plant will result in above-market
transportation costs for DTE’s ratepayers, costs that are not included in DTE’s gas
forecast. Due to the NEXUS commitment, DTE’s ratepayers are not just exposed
to the risks of the volatility and uncertainty of the gas commodity market; they also
are exposed to the risks of the markets for pipeline capacity in the region –
specifically, the risk of whether new pipeline capacity from Michigan to western
Pennsylvania and Ohio will be economic.
5 Tr 922. Mr. Beach raised concerns that the significant increase in pipeline capacity to the
Marcellus/Utica region could result pipeline expansion that exceeds production. Mr. Beach also
explained reasons for excess pipeline build-out. 5 Tr 924. Mr. Beach further testified that,
because the long-term cost of NEXUS capacity is half the pipeline’s as-billed rate, “The abovemarket pipeline costs of NEXUS would increase the gas plant’s fuel costs by about $0.37 per
MMBtu, resulting in a 5% increase in the gas plant’s overall costs.” 5 Tr 927.
In rebuttal to Mr. Beach, Mr. Swiech testified:
First, Witness Beach appears to arbitrarily assume that the Kensington to MichCon
CityGate basis spread will be 50% of the NEXUS transportation cost, and makes no
attempt to support that assumption. Second, Witness Beach incorrectly applies his
arbitrary basis spread assumption to the entirety of the proposed plant’s
approximately 180,000 [dekatherms per day] Dth/d required transportation
capacity. He chooses to ignore the fact that only 45,000 Dth/d of NEXUS capacity
is incremental to the decision to build the plant. Even if Witness Beach’s basis
spread assumption is correct, the impact on the levelized cost would only be 1.4%
because it only impacts 45,000 Dth/ of transportation capacity. This fact is
demonstrated by adjusting the calculation used in Witness Beach’s model to only
account for 45,000 Dth/d of capacity, and the corrected calculation and result is
provided in Exhibit A-67.
8 Tr 2565.
Mr. DiDomenico testified that although supply from the NEXUS pipeline could be used by
several of DTE Electric’s gas plants, the pipeline is expected to also supply the proposed NGCC
plant. 6 Tr 1560. Mr. DiDomenico added that it may be advantageous for DTE Electric to secure
low-cost supply and transporting that supply via the NEXUS pipeline, rather than relying on thirdparty, potentially interruptible, supplies at the Mich Con City Gate. 6 Tr 1561-1562.
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 Despite the possible advantages presented by the NEXUS pipeline, Mr. DiDomenico stated
“I am concerned that this strategy as presented in this filing, ignores the potential mismatch in the
timing of the in-service dates for the Company’s Proposed Plant versus that of the NEXUS Gas
Transmission system[,]” noting that there have been several construction delays already as DTE
Electric admits. 5 Tr 1563.
Mr. DiDomenico admitted that DTE Electric has not specifically stated that it intends to rely
on the NEXUS pipeline for supply, noting that the company intends to enter into firm
transportation agreements with several suppliers. However, according to Mr. DiDomenico,
“[m]aximizing use of the NEXUS contract by flowing as much supply as possible by dedicating it
to a baseload plant will reduce the average cost of gas per unit, which contributes to lower electric
generation costs.” Mr. DiDomenico also testified that DTE Electric has not developed plans or
cost estimates for how it intends to deliver gas from the interstate pipeline to the NGCC plant,
noting that the current distribution infrastructure cannot deliver the volumes required for the
project. 6 Tr 1565.
In summary, Mr. DiDomenico opined that there are still some risks associated with the
company’s plan to obtain firm gas supply. He therefore recommended that DTE Electric develop
a contingency plan to address these risks and provide the plan to the Commission for approval.
In rebuttal, Mr. Swiech testified that Mr. DiDomenico misunderstood certain aspects of the
precedent contract between the company and NEXUS, noting that DTE Electric intends to submit
the contract for Commission approval once the pipeline is operational. 8 Tr 2567. With respect to
Mr. DiDomenico’s concerns about delays Mr. Swiech testified that the delays were the result of
issues at the FERC, but that FERC issued a certificate of public convenience and necessity on

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 August 25, 2017. Thus, according to Mr. Swiech, the NEXUS pipeline is expected to be in service
September 2018. 8 Tr 2568.
With respect to the connection between the interstate pipeline and the proposed project,
Mr. Swiech explained that on January 8, 2018, DTE Electric issued an RFP for the interconnection
project, with proposals expected by mid-February. Mr. Swiech further explained that the cost of
the interconnecting facilities is already included in the transportation costs included in the case.
8 Tr 2570.
ELPC did not address the company’s rebuttal in its initial brief and the Attorney General did
not address the NEXUS pipeline issue at all in his brief. The Commission finds that DTE Electric
adequately addressed the issues related to the NEXUS pipeline in its rebuttal and briefing.
Specifically, the Commission observes that Mr. Beach’s testimony was speculative, and appears to
have been based on a miscalculation of the amount of gas to be supplied to the proposed project by
the NEXUS system. In addition, as pointed out by DTE Electric in its brief, the NEXUS pipeline
contract is subject to approval in a PSCR proceeding, once the pipeline is in service. Finally, the
Commission is satisfied that concerns about delays in the in-service date for the NEXUS pipeline
have been resolved and that the interconnection costs between the interstate transmission system
and the NGCC plant were included in the transportation costs that were modeled.
D. Michigan Environmental Protection Act
In their initial brief, MEC/NRDC/SC contend that, in addition to state and federal emissions
and water discharge requirements, the Commission must also determine that the proposed project
complies with MEPA. MCL 324.1705(2) provides:
In administrative, licensing, or other proceedings, and in any judicial review of
such a proceeding, the alleged pollution, impairment, or destruction of the air,
water, or other natural resources, or the public trust in these resources, shall be
determined, and conduct shall not be authorized or approved that has or is likely to
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 have such an effect if there is a feasible and prudent alternative consistent with the
reasonable requirements of the public health, safety, and welfare.
In State Highway Comm’n, v Vanderkloot, 392 Mich 159, 185-186; 220 NW2d 416 (1974) our
Supreme Court emphasized that that state agencies must consider environmental impacts in
permitting decisions:
While . . . [MEPA] creates a procedural cause of action, … [it] also establishes
substantive standards imposed upon those engaging in, or likely to engage in,
pollution, impairment, or destruction of the air, water or other natural resources or
the public trust therein. In relevant part, . . . [it] proscribes such pollution,
impairment, or destruction unless it is demonstrated that ‘. . . There is no feasible
and prudent alternative to (the polluting, impairing, or destroying entity's) Conduct
and that such conduct is consistent with the promotion of the public health, safety
and welfare in light of the state's paramount concern for the protection of its natural
resources from pollution, impairment or destruction.’ This substantive
environmental guideline is applicable to the Commission's administrative
condemnation determinations.
The applicability of MEPA to this proceeding is not clear based on existing case law. The
Commission recognizes that MEPA applies to agency actions generally, but again observes that
DTE Electric’s request is not compulsory, and the company may build the proposed plant without
a CON. Moreover, the granting of a CON does not authorize the company to actually proceed
with construction as it would still need to obtain required environmental permits through other
agency proceedings. But given the potential environmental impact power generation sources can
have on the environment and how the review of “feasible and prudent” alternatives is an integral
part of an IRP in a CON proceeding, the Commission concludes that, in addition to the
requirements under Section 6s, it is appropriate to determine under MEPA: (1) whether the
proposed project would impair the environment; (2) whether there was a feasible and prudent
alternative to the impairment; and, (3) whether the impairment is consistent with the promotion of
the public health, safety, and welfare in light of the state’s paramount concern for the protection of
its natural resources from pollution, impairment or destruction.
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 MEC/NRDC/SC argue that “When a prima facie case of harm or potential harm is established,
the entity emitting the pollution must demonstrate that there is ‘no feasible and prudent alternative’
that would achieve the objective of the proposed action.” MEC/NRDC/SC’s initial brief, p 11.
DTE Electric strongly objects to MEC/NRDC/SC’s “newly-announced MEPA claim” arguing
that the claim “fails by MEC/NRDC/SC’s own cited authority since MEC/NRDC/SC have not
‘established’ a ‘prima facie case of harm or potential harm.’” According to DTE Electric,
“Indeed, they have not even attempted to make any showing and cite no evidence upon which any
such potential harm could be found[.]” DTE Electric’s reply brief, p. 9.
In addressing the substance of MEC/NRDC/SC’s argument, DTE Electric points to evidence
in the record showing that the proposed project will comply with all federal, state, and local
environmental regulations, as well as evidence demonstrating that closure of eight coal-fired units,
coupled with the proposed NGCC unit, will result in an overall reduction in emissions. 5 Tr 14441447, Exhibit A-36. Moreover, DTE Electric posits that no party offered a reasonable and feasible
alternative to the proposed project, therefore the NGCC plant should be approved.
The Commission agrees with DTE Electric that a comprehensive view of the company’s
course of action, which includes the closure of eight coal-fired units and replacement with an
advanced-class NGCC, results in lesser harm to the environment than the status quo. Accordingly,
the Commission finds that, consistent with the agency requirements under MEPA, there is no
environmental impairment as a result of the proposed project, and if there were, there is no
reasonable and feasible alternative to the impairment. Thus, the Commission finds the
environmental impairment consistent with the promotion of the public health, safety, and welfare
in light of the state’s paramount concern for the protection of its natural resources.

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 THEREFORE, IT IS ORDERED that:
A. DTE Electric Company is granted a certificate of necessity pursuant to MCL 460.6s that
the power to be supplied as a result of the proposed construction of a 1,100 megawatt natural gas
combined cycle unit at the site of the Belle River Power Plant in East China Township, is needed.
B. DTE Electric Company is granted a certificate of necessity pursuant to MCL 460.6s that
the size, fuel type, and other design characteristics of the 1,100 megawatt natural gas combined
cycle unit represent the most reasonable and prudent means of meeting the power need.
C. DTE Electric Company is granted a certificate of necessity pursuant to MCL 460.6s that
the estimated purchase or capital costs of and the financing plan for the 1,100 megawatt natural
gas combined cycle electric generation facilities, including, but not limited to, the costs of siting
and licensing the electric generation unit and the estimated cost of power from the electric
generation facilities will be recoverable in rates from the company’s customers.
D. Pursuant to MCL 460.6s(6), the Commission approves $951.8 million for the construction
of the natural gas combustion turbine electric generation facilities. This amount includes
$934 million for power island equipment and engineering, procurement and construction costs and
$17.8 million for contingency costs. Only actual amounts incurred up to $951.8 million shall be
recoverable through rates.
E. DTE Electric Company shall file a list of environmental permits to be obtained, updated as
necessary, and an affidavit attesting that the company has obtained all necessary permits as set
forth in the order.
F. In DTE Electric Company’s integrated resource plan filing on March 29, 2019, the
company shall include an additional scenario that evaluates a portfolio consisting of energy
efficiency, renewable energy, demand response, storage, and other non-fossil fuel options,

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 ramping up over the years preceding 2029, that could augment the approved natural gas combined
cycle plant in 2022, and replace the capacity and energy lost due to the retirement of the Belle
River Power Plant.
G. In DTE Electric Company’s integrated resource plan filing on March 29, 2019, DTE
Electric Company shall provide an updated rate impact analysis related to the approved project,
consistent with the discussion in this order.
H. DTE Electric Company and the Commission Staff shall collaborate with the Midcontinent
Independent System Operator Inc. and International Transmission Company on reliability
planning for coal retirements.
I. The Commission Staff shall evaluate and make recommendations for best practices for
requests for proposals, competitive bidding, and risk assessment to be included in the integrated
resource plan filing requirements and integrated resource plan guidelines.
J. In the detail specified by the Commission Staff, DTE Electric Company shall annually file,
or more frequently if required by the Commission, reports to the Commission regarding the status
of any project for which a certificate of necessity has been granted, including an update concerning
the cost and schedule of that project pursuant to MCL 460.6s(7).
The Commission reserves jurisdiction and may issue further orders as necessary.

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 Any party desiring to appeal this order must do so by the filing of a claim of appeal in the
Michigan Court of Appeals within 30 days of the issuance of this order, under MCL 462.26. To
comply with the Michigan Rules of Court’s requirement to notify the Commission of an appeal,
appellants shall send required notices to both the Commission’s Executive Secretary and to the
Commission’s Legal Counsel. Electronic notifications should be sent to the Executive Secretary at
mpscedockets@michigan.gov and to the Michigan Department of the Attorney General - Public
Service Division at pungp1@michigan.gov. In lieu of electronic submissions, paper copies of
such notifications may be sent to the Executive Secretary and the Attorney General - Public
Service Division at 7109 W. Saginaw Hwy., Lansing, MI 48917.
MICHIGAN PUBLIC SERVICE COMMISSION

________________________________________
Sally A. Talberg, Chairman

________________________________________
Norman J. Saari, Commissioner

________________________________________
Rachael A. Eubanks, Commissioner
concurring in a separate opinion
By its action of April 27, 2018.

________________________________
Kavita Kale, Executive Secretary

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 STATE OF MICHIGAN
BEFORE THE MICHIGAN PUBLIC SERVICE COMMISSION
*****
In the matter of the application of
DTE ELECTRIC COMPANY for approval of
certificates of necessity pursuant to MCL 460.6s, as
amended, in connection with the addition of a natural
gas combined cycle generating facility to its
generation fleet and for related accounting and
ratemaking authorizations.

)
)
)
)
)
)
)
)

Case No. U-18419

CONCURRING OPINION OF COMMISSIONER RACHAEL A. EUBANKS
(Submitted April 27, 2018)
This proceeding, which has culminated in granting DTE Electric Company the three
Certificates of Necessity that the company applied for, was extraordinarily complex and
contentious. This is manifested in the thousands of pages of company and intervenor testimony
that formed the evidentiary record, as well as public comment. With so much information
available, a number of differing conclusions could be drawn. While it does not change the final
outcome, I am making additional observations regarding the application, proceeding, evidence,
and process.
As has been discussed numerous times throughout this order, DTE Electric made a clear and
compelling case for the need to build a new facility in the near term. The upcoming wave of
retirements of Trenton, River Rouge, St. Clair, and Belle River in the 2020s due to concerns
related to age, ongoing maintenance expenses, and environmental issues and compliance costs are
thoroughly discussed in the majority opinion and my concurrence in that finding will not be
repeated here.

 The question of whether this plant “represents the most reasonable and prudent means of
meeting that power need” is far less clear cut, in my view. DTE Electric has applied for a 1,100
MW natural gas fueled combined cycle electric generation facility. While this proposal may be
economically efficient from a construction and siting standpoint, the design introduces a level of
risk due to the use of a single-fueled resource that has experienced historically volatile pricing. 5
Tr 232, 913-930. A single generating large-scale resource is also finite, leaving less room for
emerging technologies, increased demand response, renewable energy technologies, or energy
efficiency measures over its expected 30-year useful life. In short, I am not certain that putting all
the eggs in one basket is the best, or only, strategy to follow. To me, DTE Electric did not make a
strong showing that it had fairly and thoroughly explored alternative solutions to meet near term
electricity demand that could have resulted in less risk for customers. Ultimately, however, no
party proved that there was a more reasonable and prudent option to meet this essentially
uncontested need for near-term investment in electric generation.
The potential risk this plant poses for customers was also not lost on intervenors who spent
incredible time and resources to build their own models and run alternate scenarios without the
benefit of having all the details necessary to do so. Because DTE Electric was not fully
transparent in its modeling, it is understandable that intervenors were unable to perfectly replicate
DTE Electric’s set up and therefore did not provide a true “apples-to-apples” comparison. 5 Tr
210-211, 324, 452, 696, and 6 Tr 1570. This in and of itself is important to uncover; modeling
applications, whether it’s Strategist, PROMOD, or another option, depend on far more inputs than
what DTE Electric made available to other parties. Instead of making their process more
transparent and using it as an opportunity to gain stakeholder support for its approach, DTE
Electric chose to entrench itself in unresponsiveness, denying crucial discovery requests, including

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Concurring Opinion of Commissioner Rachael A. Eubanks

 the Commission Staff’s request for DTE Electric to run additional scenarios. 5 Tr 195-196;
October 10, 2017 Ruling Granting Motion to Compel Discovery. This is not an acceptable
practice when the integrity of this Commission’s process is dependent on stakeholder input and
transparency so we as Commissioners can make an informed decision that best represents the
public interest. Even with those challenges, I commend the work of the Staff and intervenors
whose efforts were invaluable to me as I sorted through their analyses of different paths that
demonstrated there is no one answer for filling DTE Electric’s proven need. That said, the
alternatives presented introduced other significant risks to the analysis given the near term need
that I viewed as more significant than DTE Electric’s proposal, such as depending on energy waste
reduction or demand response to ramp up in an unprecedented time frame and quantity, or utilizing
renewable energy technologies that have not been proven in Michigan’s unique climate and
geography. 6 Tr 1773-1839. Any economic benefits, once adjusted for DTE Electric’s modeling
assumptions, did not overcome a reasonable range of deviation considering the array of projections
that have to be made in any scenario. Id.
Yet, in evaluating “other electric resources that could defer, displace, or partially displace the
proposed generation facility,” I found that there seemed to be gaps in the record that represented
options I thought logical to consider. For example, in the DTE Electric IRP Exhibit A-4, multiplesized gas plants were considered early in the modeling process but were not followed through or
thoroughly vetted by the intervenors in the same manner as the “all or nothing” full displacement.
As a result, partial displacement options utilizing a smaller plant were underdeveloped in the
record. While perhaps somewhat more expensive on a per kilowatt-hour basis at the outset, fully
modeling a smaller plant alongside additional renewable energy, energy efficiency programs, load
management, and demand response may have been tremendously valuable in understanding ways

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Concurring Opinion of Commissioner Rachael A. Eubanks

 to mitigate fuel risk for customers, and associated cost tradeoffs under various assumptions and
scenarios. Unfortunately, the deficiency of the record in this area left me unable to realistically
consider this option. As Staff witness Simpson pointed out in her direct testimony, DTE Electric
did not demonstrate or explain that it crafted its model to select resources on an equitable basis and
she had additional concerns with the modeled sizes of generic resources. 5 Tr 209-216.
Other alternatives, other than plant size, also did not seem to be fully evaluated by DTE
Electric. Staff and witnesses in their testimony argued that DTE Electric did not assess and model
demand response (DR) to its full potential and should have modeled scenarios with higher DR
assumptions. 5 Tr 261, 696, 329-330, 424. Similarly, the Staff and intervenors argued DTE
Electric should have used 2% energy efficiency in all of its models, as opposed to the 1.5% used in
the majority of DTE Electric’s model assumptions. 5 Tr 234, 209, 696, 329-330, 367. With
respect to renewable energy, several intervening parties were concerned that DTE Electric’s
modeling of wind and solar were biased against renewable resources, specifically that the costs
were overinflated and the blocks were too large. 5 Tr 456, 469, 471, 474. As a result, it was
nearly impossible for these options to be chosen in any modeling scenario. 5 Tr 478. DTE
Electric’s alternatives analysis included a 950 MW combustion turbine in the model, making the
alternatives unlikely to be chosen as they were crowded out. 5 Tr 444-499, 212-213. Further, gas
price uncertainty once again came into play in modeling as intervenors disputed DTE Electric’s
use of a short-term Henry Hub gas price forecast from 2018-2022 which transitions to a long-term
forecast from PACE Global. 5 Tr 915, 949. Such flaws cast doubt onto DTE Electric’s modeling
process, but in my view, the alternatives modeled by the intervenors also had flaws (6 Tr 17721839), albeit somewhat due to DTE Electric’s lack of full transparency.

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Concurring Opinion of Commissioner Rachael A. Eubanks

 This Commission, including this Commissioner, carefully follows the letter of the law, and
there is no question the provisions for the IRP in Section 6s governed this proceeding and we
applied those provisions faithfully in our decision making. The provisions in that section of the
law date back to 2008 and apply to this proceeding. They were updated in 2016, when the
Legislature and Governor enacted an overhaul of Michigan’s energy laws, which includes a
comprehensive framework for how the Commission should shape Michigan’s energy future,
including reintroducing a standalone IRP (outside of a CON) in Section 6t that allows for a more
holistic and inclusive process for how major resource decisions will be made. I am grateful for
those changes because I believe it will improve our process and will better incorporate a variety of
perspectives instead of starting from a specific utility proposal. In this case, intervenors argued
that certain modeling runs or sensitivities that the Commission has laid out in its Section 6t IRP
filing requirements should have been included because they would have produced a different
result. While I disagree that the Commission should have evaluated DTE Electric’s proposal
through the lens of the Section 6t IRP, it is a fair question to consider how critical pieces of the
legislation, once having had the ability to be fully implemented, would have impacted the results
of this proceeding.
A number of other factors, including the impact of the Tax Cuts and Jobs Act (TCJA), were
raised by intervenors – both in terms of the upfront cost of the plant and the TCJA’s impact on the
costs of the alternatives – yet were not quantified in a meaningful way. It is a given that even in an
expedited 270 day proceeding for a CON, there will be changes to the project cost that are outside
of the utility’s control. To DTE Electric’s credit, the company made attempts to mitigate potential
cost fluctuations. We cannot restart the process for every possible change to those costs.
However, had the record demonstrated a sense of the magnitude of the changes that occurred as a

Page 5
Concurring Opinion of Commissioner Rachael A. Eubanks

 result of the TCJA, and that magnitude was meaningful, it could have warranted a revisiting of the
upfront cost and alternatives analysis.
Another example of a concern I saw in this case was the bidding process that DTE Electric
undertook when it sought alternatives to building itself. I see merit in the intervenors’ arguments
that limiting the term of the PPA to seven years to align with DTE Electric’s capacity need limited
the potential for a robust response to the solicitation. 5 Tr 200-201, 607-623. In addition, those
parameters did not provide an appropriate comparison to the DTE Electric build option. Yet no
entity utilized a provision in the law where they could approach the Commission directly with a
proposal. In the absence of such a proposal I must assume that such alternatives are simply not
viable for this particular need.
In the end, the need is too near term and the stakes for customers are too high for me to
consider any alternate path contained in this record to be a more reasonable and prudent option
than the one presented by DTE Electric. DTE Electric is taking on an enormous responsibility to
the public in building this plant and I want to assure the public that the Commission and its Staff
will be monitoring this build extremely closely. While the process of determining what to build
will be different going forward, I ultimately see this plant as a part of Michigan’s transition to an
energy future that is adaptable, reliable, affordable, and protective of our environment.

MICHIGAN PUBLIC SERVICE COMMISSION

________________________________________
Commissioner, Rachael A. Eubanks

Page 6
Concurring Opinion of Commissioner Rachael A. Eubanks

 PROOF OF SERVICE
STATE OF MICHIGAN )
Case No. U-18419

County of Ingham

)

Lisa Felice being duly sworn, deposes and says that on April 27, 2018 A.D. she
electronically notified the attached list of this Commission Order via e-mail transmission,
to the persons as shown on the attached service list (Listserv Distribution List).

_______________________________________
Lisa Felice
Subscribed and sworn to before me
this 27th day of April 2018

_____________________________________
Steven J. Cook
Notary Public, Ingham County, Michigan
As acting in Eaton County
My Commission Expires: April 30, 2018

 Service List for Case:

U-18419

Name

Email Address

Amit T. Singh
Amy Monopoli
Bryan A. Brandenburg
Cassandra R. McCrae
Celeste R. Gill
Christopher M. Bzdok
David S. Maquera
DTE Energy Company
Heather M.S. Durian
Jason T. Hanselman
Jean-Luc Kreitner
Jill M. Tauber
John A. Janiszewski
Kyle Asher
Laura A. Chappelle
Lydia Barbash-Riley
Margrethe Kearney
Michael J. Pattwell
Michael J. Solo Jr.
Richard J. Aaron
Robert A.W. Strong
Roger L. Myers
Sean P. Gallagher
Shannon Fisk
Shannon Fisk
Spencer A. Sattler
Stephen A. Campbell
Stephen J. Videto
Suzanne Sonneborn
Tim Lundgren
Toni L. Newell
Tracy Jane Andrews

singha9@michigan.gov
amonopoli@itctransco.com
bbrandenburg@clarkhill.com
cmccrae@earthjustice.org
gillc1@michigan.gov
chris@envlaw.com
maquerad@dteenergy.com
mpscfilings@dteenergy.com
durianh@michigan.gov
jhanselman@dykema.com
jkreitner@elpc.org
jtauber@earthjustice.org
janiszewskij2@michigan.gov
kasher@dykema.com
lachappelle@varnumlaw.com
lydia@envlaw.com
mkearney@elpc.org
mpattwell@clarkhill.com
solom@dteenergy.com
raaron@dykema.com
rstrong@clarkhill.com
rmyers@myers2law.com
sgallagher@clarkhill.com
sfisk@earthjustice.org
sfisk@earthjustice.org
sattlers@michigan.gov
scampbell@clarkhill.com
svideto@itctransco.com
sonneborns@michigan.gov
tjlundgren@varnumlaw.com
tlnewell@varnumlaw.com
tjandrews@envlaw.com