STATE OF MICHIGAN

BEFORE THE MICHIGAN PUBLIC SERVICE COMMISSION In the matter of the application of CONSUMERS ENERGY COMPANY Case No. U-20165 for approval of an integrated resource plan (e-file paperless) under MCL 460.6t and for other relief. /

MICHIGAN PUBLIC SERVICE COMMISSION STAFF’S REPLIES TO EXCEPTIONS

MICHIGAN PUBLIC SERVICE COMMISSION STAFF

Spencer A. Sattler (P70524) Heather M.S. Durian (P67587) Amit T. Singh (P75492) Daniel E. Sonneveldt (P58222) Assistant Attorneys General Public Service Division 7109 W. Saginaw Hwy., 3rd Floor Lansing, MI 48917 Telephone: (517) 284-8140 DATED: March 11, 2019

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Table of Contents

Page No.

Introduction ......................................................................................................... 3

Response to Consumers ...................................................................................... 4

Staff stands by its proposed 50-50 resource split, but it should not be paired with the Company’s proposed financial compensation mechanism. ....................................................................... 5

The Company’s compromise position is better than its original position but still too expensive for ratepayers. ............... 5

The Company’s original proposal is unlawful. ........................... 10

The Company should follow a fair and transparent competitive-bidding process until the Commission approves uniform rules and processes. ......................................................................................... 14

The ALJ did not find annual solicitations to be unreasonable or imprudent. .............................................................................................. 17

Costs eligible for preapproval do not include operations and maintenance costs, the unrecovered book value of generating assets, or decommissioning costs. .......................................................... 18

Consumers should improve the granularity of its load forecast. ......... 24

Response to the Midland Cogeneration Venture (MCV) and the Association of Businesses Advocating Tariff Equity (ABATE) ....................... 24

Response to the Solar Energy Industries Association (SEIA) ......................... 27

Conclusion ......................................................................................................... 29

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Introduction

The Consumers Energy Company’s integrated resource plan has generated

controversy, some merited and some not. The controversial issues include, among

other things, the Company’s proposed financial compensation mechanism, its

decision not to purchase all of the capacity in its interconnection queue, its decision

to retire certain coal units but not others, and the need for procedures to govern the

competitive-bidding process and requests for proposals. Despite this controversy,

the parties are aligned on several issues. For instance, most parties support the

Company’s innovative competitive-bidding proposal if the solicitation process is

inclusive, unbiased, and transparent. Most parties also oppose the Company’s

request for an incentive on power purchase agreements that it enters in the future.

Staff falls into both camps. It supports competitive bidding, but it opposes any

financial incentive that is more than needed to spur this process. Staff’s proposed

alternative to an incentive—to allow the Company to own 50% of the generating

assets it procures and contract for the other 50% through competitive solicitations—

would drive down prices and facilitate transmission planning.

As for the other issues, although Staff acknowledges that the Company’s

capacity outlook has changed slightly since the Company first filed its plan, Staff

still agrees with the Company’s decision not to purchase all of the capacity in its

interconnection queue. Instead, the Company should use its proposed competitive-

bidding process to slowly secure additional supply- and demand-side resources in

small increments that allow the Company to adapt as circumstances change. Staff

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agrees with the Company’s decision to retire Karn Units 1 & 2 in 2023 but not to

retire Campbell Units 1 & 2 early (subject to change in a future plan case). Finally,

Staff agrees that the Commission should implement uniform standards on best

practices for competitive bidding and requests for proposals. But the Commission

should implement interim standards that allow utilities to move forward with RFPs

in the meantime.

Response to Consumers

Consumers should be commended for proposing a plan to procure solar

generation through a competitive-bidding process, to retire old coal generating

units, and to replace the lost capacity with demand response, energy waste

reduction, and conservation voltage reduction. Despite filing a cutting-edge plan,

the Company requested an extravagant incentive that violates the law by exceeding

the Company’s weighted average cost of capital. (Staff’s Revised Initial Br, pp 66-

67, 80; Staff’s Reply Br, pp 3–5.) The Company’s proposed incentive is also more

than it needs to persuade it to enter into power purchase agreements. If the

Commission decides that the Company needs an incentive, it should approve one

that is high enough to spur competitive bidding, but no higher. (See Staff’s Revised

Initial Br, p 77-81.) Staff’s proposed 50-50 split—either in lieu of an incentive or

combined with a much lower incentive—is also a good alternative that would spur

competition, drive down prices, and improve transmission planning.

Staff opposes the Company’s attempt to include operations and maintenance

(O&M) expenses, the unrecovered book value of Karn Units 1 & 2, and

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decommissioning costs in its plan because they are outside the statutory scope of

this case.

Staff stands by its proposed 50-50 resource split, but it should not be paired with the Company’s proposed financial compensation mechanism.

While Consumers continues to support its originally proposed financial

compensation mechanism, the Company has clarified that alternatives would be

acceptable in the right circumstances, meaning that it could support, with some

changes, proposals presented by Staff and other parties. (Consumers’ Exceptions, p

91.) Staff is pleased by this development because it was not clear on the record that

the Company would accept anything less than its proposal. The ALJ reasonably

concluded, based on the record, that the Company was taking an all-or-nothing

approach to its proposed financial compensation mechanism. (PFD, p 266.) But the

Company’s Exceptions are evidence that this is no longer the case and that it is

willing to accept something less than it proposed. Unfortunately, however, even the

Company’s compromise position is too expensive for ratepayers.

The Company’s compromise position is better than its original position but still too expensive for ratepayers.

Staff witness Paul Proudfoot proposed that, in lieu of a financial incentive,

the Commission could allow Consumers to own 50% of the generating assets it is

proposing to procure and contract for the other 50% through its competitive bidding

proposal. (9 TR 2564-2566.) Mr. Proudfoot testified that this construct would

continue “the fifty percent limitation on company-owned resources that was

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included in [2008] PA 295,” which “led to increased competition and drove prices

down for customers in Michigan, including lower prices for Company-owned

renewable resources.” (9 TR 2564.) For the 50% of Company-owned generation, the

Company could, and hopefully would, competitively bid its engineering,

procurement, or construction contracts, which would further drive down costs.

In addition to the price benefits, Staff’s 50-50 proposal has other benefits as

well. Mr. Proudfoot said, “Allowing the Company to own a portion of the new

resources will also provide the Company with greater control over the maintenance

and operation of the equipment, greater insight into the performance of the

equipment, and better equip the utility to forecast the output from the solar

resources.” (9 TR 2566.) If the Company owns up to 50% of its resources, then it

will have early knowledge of the location of these resources. By contrast, when the

Company procures resources through requests for proposals (RFPs) and competitive

bidding, the Company does not learn the location of resources until much later in

the process. Knowing the location early allows the Company to better coordinate

generation and transmission planning going forward. (Staff’s Reply Br, pp 12–13.)

Staff agreed with METC that coordinated generation and transmission

planning—using IRP planning information rather than less certain information

from interconnection queues—is needed to develop a more efficient and robust

transmission grid. Coordinated planning could also help 1) ensure that resources

are interconnected in an orderly fashion at optimal locations, 2) achieve the right

balance between transmission and generation investment, and 3) inform the

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Company’s RFP process. (Staff’s Reply Br, p 12.) While sourcing all future

resources from RFPs or competitive solicitations may lower costs for resources, it

may also hamper the transmission and distribution systems and increase costs.

Staff’s 50-50 proposal combines the benefits of coordinated generation and

transmission planning with the cost benefits of competitive solicitation. This is why

Staff continues to support the 50-50 split in lieu of a PPA incentive or in

combination with a much lower incentive. Consumers too is receptive to this

proposal, but it has suggested that the 50-50 split should be coupled with “the FCM

methodology proposed by MEC witness Jester, which can be calculated at

9.27%.” (Consumers Exceptions, p 92.) Although this compromise proposal is an

improvement over its originally proposed incentive, it is still too expensive for

ratepayers.

With Staff’s 50-50 proposal, there is no need for an incentive—certainly not a

high incentive. The alternative incentives that Staff proposed, even without the 50-

50 split, were much lower than the 9.27% that Consumers is now proposing as an

alternative together with the 50-50 split. (See Staff’s Revised Initial Br, pp 66–81.)

But Staff’s 50-50 proposal would significantly mute the need for a financial

incentive. Considering the Company’s PPAs soon to expire, the Company’s plan

would not increase the total amount of purchased power in its generation portfolio

for several years. So in the short term, the Company’s plan would maintain the

status quo, and the Company does not need an incentive to maintain the status quo.

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While Consumers characterizes its IRP as the replacement plan for Karn

Units 1 & 2 in 2023, the IRP is also replacing the Palisades PPA, which is a major

source of energy and capacity, not to mention the other PPAs that will be expiring

not long afterward. Company witness Blumenstock testified, “The Company’s PPA

with Palisades will terminate on April 11, 2022. . . . The large decline in surplus

capacity in 2021 is attributed to the loss of 765 ZRCs from the Palisades PPA.” (6

TR 248.) The following chart from the Company’s IRP report shows the Palisades

retirement and other major upcoming generation replacements and retirements:

(Exhibit A-2, p 7.)

As this chart shows, before the Company retires all of its coal units in the 2030s and

2040s, it is planning to replace large PPAs as well as significant amounts of

Company-owned generation. (Exhibit A-2, p 7.) The ratio of PPAs to Company-

owned resources would be similar to acquiring 50% of new resources as PPAs

through competitive bidding and 50% as Company-owned generation.

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The 50-50 split proposal is much closer to the status quo than Consumers

portrays it. Company witness Sri Maddipati, for example, said that Staff’s 50-50

proposal would shift “the Company’s owned generation from nearly 70% to 50% over

time [and] would still be a dramatic shift.” (7 TR 753.) In the long-term, the 50-50

split would shift generation as described, but it would take the Company many,

many years to get there. In the short and intermediate term, the 50-50 proposal

could lead the Company to replace major PPAs with 50% Company-owned

generation, largely maintaining the status quo. Since the Company does not have a

financial compensation mechanism today, a plan that incorporates a 50-50 split and

maintains the status quo should not be coupled with anything more than a very

small incentive, if any incentive at all.

In sum, there is no longer a need to reject the Company’s plan believing that

it will not accept a plan with an incentive lower than the one it proposed. The

Company has shown that it will accept less. This may even be true of the

Company’s compromise position. The Company might accept an incentive lower

than 9.27% if it is in combination with a 50-50 resource split, which is why Staff

continues to support the 50-50 split with no incentive or a lower one.

As Staff proposes it, the 50-50 split has a lot to offer. The same 50-50 split

that began with Act 295 has succeeded in reducing costs. It could also help Staff,

MISO, utilities, and other interested stakeholders coordinate generation and

transmission planning. But given the significant PPAs that the Company plans to

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replace in the next decade, if Staff’s 50-50 proposal is coupled with an incentive, it

should in no circumstance be higher than Staff’s proposed incentive.

The Company’s original proposal is unlawful.

The Company continues to advocate for a financial compensation mechanism

that is tied to imputed debt. It argues that its proposed incentive is needed to

“fairly incorporate the impacts of imputed debt caused by PPAs so that the costs are

visible at the time of procurement and so that there is a built-in vehicle for recovery

of those costs.” (Consumers’ Exceptions, p 67.) But imputed debt should be

considered in a rate case together with the Company’s entire cost of capital. A 2008

Brattle Group report that the Company relied on to support its proposed incentive

reveals that most states that consider imputed debt do so in a general rate case.

Staff witness Bob Nichols evaluated this report, testifying that when the report was

written, only six state commissions considered imputed debt at all. And half of

these state commissions considered imputed debt on power purchase agreements in

general rate cases where they could also evaluate the utilities’ total cost of capital.

(9 TR 2806.) Consistent with this accepted practice, Mr. Nichols recommended that

the Commission consider imputed debt “in the context of setting a reasonable cost of

capital in a general rate case.” (9 TR 2806.)

The Colorado Public Utilities Commission explained why it makes sense to

evaluate imputed debt in rate cases. By doing so, it said, “all the moving parts of

the issue will be examined at the same time, including the impact on the Company’s

financial health as well as the impact on ratepayers.” (Exhibit S-1, p 3, citation

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omitted.) The Colorado Commission rejected a utility’s request for an imputed-debt

adder on PPA bid evaluations. It reasoned that in a resource-acquisition docket “all

aspects of Public Service’s capital costs as they relate to imputed debt are not

examined as they would in a rate case.” (Id.) Other states have rejected similar

attempts to consider imputed debt in PPA bid evaluations or in utility IRPs. (See

Exhibit S-1, pp 3-6.) Further research into how states have approached the

imputed-debt issue since the Brattle Group report confirms the report’s findings.

(See Staff’s Revised Initial Br, pp 68–69.)

Unlike states that consider imputed debt together with other cost-of-capital

issues in rate cases, Consumers views the financial incentive in isolation. It

proposes to evaluate a PPA’s imputed debt when it enters the contract, without

considering the overall return that the Company is earning and whether it is high

enough to offset the PPA’s imputed debt. (See 7 TR 740.) This led the Company to

propose an exorbitant incentive. On a 10-year PPA, the Company would earn a

13.8% incentive, while on a 20-year PPA, the Company would earn a 21.53%

incentive. (7 TR 731; 9 TR 2716.) This is far above the 5.89% total weighted

average cost of capital the Commission approved in Consumers’ last contested rate

case. (7 TR 730; 9 TR 2716.) In response to discovery, the Company estimated its

incentive’s unit cost ($/MWh), which Staff used to calculate the revenue that the

Company would have received if its existing PPAs had earned an incentive: the

total revenue would have been somewhere between $48 million to $183 million per

year. (9 TR 2804-2805.)

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By calculating a PPA’s imputed debt in a vacuum, without accounting for the

overall cost of capital, Consumers would earn a return that is higher than it needs

to be to protect its credit rating. The Company argues that it must recover its

PPAs’ imputed debt to avoid adversely affecting its credit rating.1 But the

Company’s credit rating is solid: as of “November 13, 2017, S&P [Standard & Poor’s

Financial Services, LLC] credit rating for Consumers was BBB+/ Stable/A-2.” (9 TR

2805; Exhibit S-15.1.) And the Company is already earning returns above its

authorized return on equity: “[I]n 2017, on a financial basis, the company earned

10.15% and on a ratemaking basis, earned 10.26%, with an authorized ROE of

10.1%.” (9 TR 2805; Exhibit S-15.5.) Further, the Company’s authorized return is

36 basis points above the “total US mean ROE for 2017 of 9.74%,” which has about

a “$22 million revenue requirement impact.” (9 TR 2805-2806; Exhibit S-15.6.)

This should certainly be considered when deciding how much a PPA’s imputed debt

would negatively affect the Company’s credit rating.

The imputed debt associated with PPAs “is only a very small component of

the overall outlook of a Company’s financial health.” (9 TR 2714.) Staff witness

1 Company witness Srikanth Maddipati testified that “[w]hile each of the three major credit rating agencies (S&P, Moody’s, and Fitch) have different methodologies, each agency considers the impact of imputed debt created by PPAs.” (7 TR 723.) Company witness Michael Torrey further said, “[A] competitive bid methodology presents significant risks to the Company’s ability to attract capital investment for needed infrastructure investments and provide sustainable returns to investors unless there is an incentive for the Company to enter into PPAs. Otherwise, the Company’s credit ratings could become stressed and the Company would have a bias towards constructing its own projects to own, or entering into ‘build-transfer’ agreements . . . .” (8 TR 1474, emphasis added.)

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Jesse Harlow observed that while a PPA may come with some level imputed debt, it

is not always necessary to offset that imputed debt to protect a utility’s credit

rating. Other aspects of the utility’s business “simultaneously affect [its] future

capital structure and ultimately the cost of capital.” (Id.) For example, “Company

decisions such as the termination of current PPAs, financing Company-owned

facilities, and regulatory decisions, to name a few, all play a role in the capital

structure calculation.” (Id.) This is why it makes sense to consider imputed debt

together with the Company’s capital structure and cost of capital in a rate case.

In this context, Consumers’ proposed incentive is too high. As Mr. Harlow

testified, “The Company’s calculation inappropriately combines both a PPA FCM

and an imputed debt offset mechanism into one calculation. This results in a return

that is much higher than the Company’s weighted average cost of capital (WACC)

which does not align with PA 341 of 2016 (MCL 460.6t)(15).” The Company

responds that Staff reached this conclusion by applying the Company’s proposed

incentive to the wrong base. According to the Company, “Cost of capital rates are

applied to capital balances (i.e., debt and equity), not expense balances.”

(Consumers’ Exceptions, p 82, quoting 7 TR 752-753.) This is essentially a balance-

sheet problem that Staff has already resolved. (See Staff’s Reply Br, pp 3–5.)

The Company also says that if “the law intended to cap any FCM as the PPA

expense times the Company’s WACC it could have said so explicitly.” (Consumers’

Exceptions, p 82.) This is semantics. It is just as easy to say that if the Legislature

intended to cap the incentive at the PPA’s imputed debt, “it could have said so

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explicitly.” Section 6t(15) is clear on its face and in context. See Griffith v State

Farm Mutual Auto Ins Co, 472 Mich 521, 533 (2005) (“[T]he meaning of statutory

language, plain or not, depends on context.”). Section 6t(15) allows the Commission

to authorize a PPA incentive but capped the incentive at “the utility’s weighted

average cost of capital.” MCL 460.6t(15). A utility’s Commission-approved

weighted average cost of capital is a number that can be found in most rate case

orders.

The Company should follow a fair and transparent competitive-bidding process until the Commission approves uniform rules and processes.

In response to the ALJ’s concerns that Consumers’ competitive-bidding

proposal “lacks sufficient safeguards to ensure ratepayer interests are protected,”

(PFD, p 202), the Company committed to following procedures designed to ensure a

fair and transparent process. These procedures include using an independent

evaluator during competitive solicitations, following RFP parameters the

Commission approved in Case No. U-15800, timely issuing an RFP through public

notice, and including the terms of the contract in the RFP. (Consumers’ Exceptions,

pp 37–38.) Requiring the Company to follow through with these commitments will

provide enough safeguards for now to ensure that the process is fair and open. But

Staff encourages the Commission to implement uniform standards on best practices

for competitive bidding and RFPs that all utilities can use.

Specifically, Staff recommends approving Consumers’ proposed RFP and

competitive-bidding processes, while preventing unnecessary delay to utility RFPs

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while uniform rules and regulations for these processes are under development.

Staff disagrees with the Michigan Energy Innovation Business Council (MIEBC)

and the Institute for Energy Innovation (IEI) that the Commission should approve

uniform rules and regulations for RFPs and competitive bidding before Consumers

implements competitive bidding as part of its IRP. Rather, Staff recommends that

the Commission give notice and seek comments from stakeholders and the public on

best practices for RFPs and competitive bidding in a separate docket. This docket

should move forward expeditiously, but it should not delay utility RFPs issued in

conjunction with an IRP proceeding or in accordance with a Commission-approved

IRP.

Below, the MIEBC and IEI pointed out that 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.”

(MIEBC-IEI’s Initial Br, p 4, quoting In re DTE’s Application for a Certificate of

Necessity, MPSC Case No. U-18419, 4/27/2018 Order, p 106.) Although the

Commission directed “Staff to research approaches and best practices for RFP and

competitive bidding in other jurisdictions,” it did not require Staff to complete its

study before utilities issue RFPs. (Id.) MIEBC and IEI argued that Consumers’

proposed use of RFPs and competitive bidding “should not be implemented until

such a study by Staff is completed” and uniform rules or standards are

implemented. (MIEBC-IEI’s Initial Br, p 6.) Staff disagrees with MIEBC and IEI,

but only concerning the timing of the implementation of uniform rules or standards

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on best practices. Staff agrees with MIEBC and IEI’s substantive recommendations

related to RFPs and competitive bidding.

MIEBC and IEI witness Dr. Laura Sherman testified that adoption of

uniform rules or best practices for RFPs and competitive bidding “should be done

with stakeholder input and according to best practices, including those established

in other states.” (9 TR 2839.) Staff agrees and recommends that the Commission

seek comments from stakeholders and the public on best practices for RFPs and

competitive bidding in a separate docket on a separate timeline. The separate

timeline is necessary to avoid interfering with the implementation of, not only

Consumers’ IRP, but the development and implementation of all other Michigan

utilities’ IRPs scheduled to be filed in the first half of 2019.

Act 341, Section 6t(6), requires utilities to conduct RFPs to “provide any new

supply-side generation capacity resources” and to “use the resulting proposals to

inform its integrated resource plan filed under this section and include all of the

submitted proposals as attachments to its integrated resource plan filing.” MCL

460.6t(6). The statute contemplates completed RFPs with proposals attached to the

utility-filed IRP applications, which are presently under development based on the

IRP filing requirements approved in Case No. U-18461. Changing the rules on

Michigan utilities by implementing new RFP regulations and competitive bidding

processes while their applications are under development or being litigated, as in

Consumers’ case, is not advisable.

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Staff recommends that the Commission consider all of MIEBC and IEI’s

specific proposals relating to best practices for RFPs and competitive bidding in a

separate docket addressing uniform rules and processes for all utilities. Staff

recommends that the Commission open a docket after the present IRP case is

concluded, directing Staff to file its proposed best practices for RFPs and

competitive bidding, while allowing for comments, reply comments, and a

Commission order before the end of 2019. In the interim, the Company’s proposed

RFP and competitive-bidding processes should be approved, as reflected in the

Company’s Exceptions and modified to include any of MIEBC and IEI’s

recommendations the Commission deems proper at this time.

The ALJ did not find annual solicitations to be unreasonable or imprudent.

As Consumers reads the PFD, the ALJ opposed Staff’s proposal for annual

solicitations. (Consumers’ Exceptions, pp 42–44.) This is not how Staff reads the

PFD. The ALJ undoubtedly rejected the competitive-bidding process, and if

adopted, this would necessarily preclude annual solicitations. But the ALJ did not

single out annual solicitations for criticism. Rather, the ALJ rejected the larger

competitive-bidding framework because it allegedly lacks sufficient safeguards and

gives the utility and its affiliates a potential advantage over its competitors. (PFD,

p 202.) Staff addressed these issues above, but it writes separately here to stress

that the ALJ did not object to Staff’s annual-solicitation proposal and to once again

tout Staff’s proposal.

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Annual solicitations ensure that Consumers uses the most up-to-date costs

for IRP modeling and avoided costs. (9 TR 2721.) Annual solicitations also allow

developers that would otherwise ask for PURPA contracts to bid in larger projects,

allowing for greater economies of scale and interconnection at the transmission

level. Interconnecting to the transmission network reduces the complexity and

costs of interconnection when compared to large PURPA contracts interconnecting

at the distribution level. (9 TR 2722.) The Company agrees. (8 TR 1281.)

Costs eligible for preapproval do not include operations and maintenance costs, the unrecovered book value of generating assets, or decommissioning costs.

Act 341, Section 6t(11) directs the Commission to “specify the costs approved

for the construction of or significant investment in” certain facilities or power

purchase agreements. MCL 460.6t(11). The statute goes on to list several

investments that qualify for preapproval, all of which are capital projects that the

utility builds, purchases, or purchases power from. The investments listed are “an

electric generation facility, the purchase of an existing electric generation facility,

the purchase of power under the terms of the power purchase agreement, or other

investments or resources used to meet energy and capacity needs that are included

in the approved integrated resource plan.” Id. Once approved in the IRP, the “costs

for [these] specifically identified investments” are then essentially preapproved—

i.e., “considered reasonable and prudent for cost recovery purposes”—if the utility

begins making the investment within three years of the plan’s approval. MCL

460.6t(11) and (17).

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Since only “specifically identified investments” are preapproved for cost

recovery, this phrase is important. And it can only be understood in context.

Griffith v State Farm Mutual Auto Ins Co, 472 Mich 521, 533 (2005) (“[T]he

meaning of statutory language, plain or not, depends on context.”) The phrase

“specifically identified investments” refers back to the “construction of or significant

investment in” certain facilities identified in the prior sentence. MCL 460.6t(11).

These investments are all capital investments, with the caveat described below. Id.

Consumers’ O&M costs, the Karn Units’ unrecovered book value, and those units’

decommissioning costs (all costs included in the Company’s plan) are not included in

the list of investments. The law does not guarantee these costs will be considered

reasonable and prudent for cost recovery purposes.

While a PPA may include operations and maintenance costs, and these PPA

costs may be passed on to ratepayers through the PSCR clause, (Consumers’

Exceptions, p 98), it is still a capital cost for the third party building it. More

importantly, however, a contractual PPA “investment” is fundamentally different

from an O&M “expense.” Section 6t applies only to “costs approved for the

construction of or significant investment in” certain facilities, power purchase

agreements, and other resources used to meet energy and capacity needs. MCL

460.6t(11) (emphasis added). Nowhere in Section 6t(11) or (12) does it suggest that

IRP cost preapproval extends to common O&M expenses. As Staff witness Paul

Proudfoot succinctly said, “While section 6t(11) specifically mentions the approval of

costs for investments, it does not mention the approval of costs that would be

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classified as expenses. O&M expenses would traditionally be classified as

expenses.” (9 TR 2556.)

That a PPA is a contractual investment that is different than a common

expense is also evident in Section 6s, the Certificate of Necessity (CON) section,

which should be read together with Section 6t. “Statutes that address the same

subject or share a common purpose are in pari materia and must be read together

as a whole.” People v Harper, 479 Mich 599, 621 (2007). A statute that shares a

common purpose with another statute “should be read in connection with it, as

together constituting one law.” Detroit v Mich Bell Tel Co, 374 Mich 543, 558

(1965), overruled on other grounds. Sections 6s and 6t plainly address the same

subject, even requiring the Commission to consolidate a CON case with an IRP case

if the utility is seeking preapproval for a generating unit or units totaling 225 MW

or more.

Section 6s, like Section 6t(11), empowers the Commission to preapprove costs

for certain projects and purchases, except the projects and purchases approved

through Section 6s CONs are larger than those approved in Section 6t IRPs. It

allows electric utilities to seek a CON if they are planning to “construct an electric

generation facility, make a significant investment in an existing electric generation

facility, purchase an existing electric generation facility, or enter into a power

purchase agreement for the purchase of electric capacity for a period of 6 years or

longer,” but the “construction, investment, or purchase” must be for $100 million or

more. Id. The italicized language mirrors the language in Section 6t(11) quoted

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above. See MCL 460.6t(11). And Section 6s makes clear that the investment

cannot be for common expenses, although a group of investments may be

aggregated if they are planned “for a singular purpose such as increasing the

capacity of an existing electric generation plant.” MCL 460.6s(1) (emphasis added).

O&M expenses are common expenses that, as its name implies, generally

contribute to operating and maintaining a facility, not upgrading a facility. O&M

expenses are not intended for a singular purpose like increasing the capacity of an

existing facility. Although the “singular purpose” language cannot be found in

Section 6t, Section 6s must be read together with Section 6t, and in any case, there

was no reason to include the “singular purpose” language in Section 6t because it

does not allow for aggregation like Section 6s. But this does not mean Section 6s

and Section 6t do not share the same purpose: preapproval of projects that increase

a utility’s energy and capacity resources. Constructing a facility, purchasing a

facility, or purchasing power from a facility, under Section 6t, all advance this

“singular purpose,” which is why there was no need to include the “singular

purpose” language in this section. It was understood by the nature of the projects

themselves. Because O&M expenses do not meet this “singular purpose,” they are

not eligible for preapproval.

In addition to not covering O&M expenses, Section 6t also does not cover the

Karn Units’ unrecovered book value and their decommissioning costs. These costs

do not qualify for preapproval. Not only are they not used to construct or make a

significant investment in an electric generating facility or to purchase power, these

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costs do not even go toward an investment or resource used to meet energy and

capacity needs. Consumers’ IRP is its plan going forward to meet “the utility’s load

obligations.” MCL 460.6t(3). The unrecovered book value of generating units that

have reached the end of their useful lives are sunk costs that can no longer be used

to meet these obligations. The Legislature talked about “new facilities” and

facilities “used to meet energy and capacity needs,” MCL 460.6t(11),(12), not old

plants that will soon be retired. They are clearly not the kind of costs eligible for

preapproval. And while Section 6t references existing facilities, (see Consumers’

Exceptions, pp 94–95), if these facilities are planned for retirement and will not to

be available meet “the utility’s load obligations” going forward, they are beyond the

scope of a forward-looking plan.2

Consumers has also argued that the catchall in Act 341 expands the list of

investments that qualify for preapproval. (Consumers’ Exceptions, p 99.) The Act

allows the Commission to preapprove, in addition to the capital investments listed,

“other investments or resources used to meet energy and capacity needs that are

included in the approved integrated resource plan.” MCL 460.6t(11). The

unrecovered book balance of a retired plant and its decommissioning costs do not

qualify under this catchall, as just described, but a stronger argument can be made

2 The Commission’s Integrated Resource Plan Filing Requirements also do not mention unrecovered book value or decommissioning costs in the section on cost approvals.

23

that the catchall applies to O&M expenses. The problem is that O&M expenses are

not in the same class as the investments described in the statute.

Under the doctrine of ejusdem generis, “when a general word or phrase

follows a list of specifics, the general word or phrase will be interpreted to include

only items of the same class as those listed.” Home-Owners Ins Co v Andriacchi,

320 Mich App 52, 63 (2017). O&M expenses are not in the same class as the listed

capital investments. Id. As Mr. Proudfoot testified, Section 6t(11) specifically says

that certain “investments” qualify for cost preapproval, but “O&M expenses would

traditionally be classified as expenses,” not investments. (9 TR 2556.) The catchall

in Section 6t(11) does not cover O&M expenses.

Finally, Consumers argued that “even if the provisions of MCL 460.6t did not

include the pre-approval of O&M costs, which the Company does not agree, the

Commission would still have the authority to pre-approve the recovery of O&M

costs in this proceeding.” (Consumers’ Exceptions, p 99.) Staff does not dispute the

Commission’s broad ratemaking authority, but if the Commission has discretion to

preapprove these costs under its broad ratemaking authority, it also has discretion

not to preapprove these costs consistent with Section 6t’s plain meaning. Staff

recommends that the Commission not preapprove O&M costs in this proceeding but

that it consider O&M costs in rate cases as it has traditionally done.

The upshot is that even if the Commission approves a plan with O&M costs,

sunk costs, and decommissioning costs, Consumers is not guaranteed to recover

24

those costs. The Commission can make this abundantly clear by recommending

that the Company remove these costs from its plan, MCL 460.6t(7), or simply not

identifying these costs among the costs being approved.3 See MCL 460.6t(11).

Consumers should improve the granularity of its load forecast.

Staff recommended that Consumers be directed to improve the granularity of

its load forecast, and the ALJ agreed, finding that Staff witness Olumide Makinde

provided a reasonable basis for the recommendation. (PFD, p 295.) The Company

took exception, stating that it does not have enough hourly data from smart meters

to meet this request. (Consumers’ Exceptions, p 101.) Staff understands that the

Company does not have 15 years of smart-meter data, but the Company should

continue working with Staff towards improving the granularity in its forecasts. As

such, Staff urges Consumers to continue improving its load forecast and asks the

Commission to direct the Company to work with Staff on these improvements.

Response to the Midland Cogeneration Venture (MCV) and the Association of Businesses Advocating Tariff Equity (ABATE)

MCV and ABATE continue to oppose Consumers’ proposal to retire Karn

Units 1 and 2 early in 2023. The Attorney General, who once opposed early

retirement, did not file Exceptions on this issue. MCV argues that the Company’s

retirement analysis was flawed because it did not use the Annual Energy Outlook

3 Section 6t(11) requires the Commission to “specify the costs approved,” but it does not say the costs approved have to be equal to the costs included in the plan.

25

(AEO) gas forecast as required in the Michigan Integrated Resource Planning

Parameters (MIRPP). (MCV’s Exceptions, p 5.) ABATE summarized the parties’

arguments against early retirement, saying that “the Company failed to establish

that early retirement is a reasonable and prudent option, as well as raising

contentions that the Company’s analysis overestimates the benefits of early

retirement for the units.” (ABATE’s Exceptions, p 8.)

The ALJ did not rely as heavily on the Company’s retirement analysis of the

Karn Units as she did Staff’s analysis, finding that Staff’s analysis was sufficient to

justify early retirement. (PFD, p 179.) The ALJ described Staff witness Zachary

Heidemann’s testimony that “all model runs show savings when Consumers

Energy’s gas price is used with a capacity replacement cost of 75% of CONE.” (Id.)

Mr. Heidemann said, and the ALJ apparently agreed, that the decision to retire the

units early is not a high-risk decision. And while the Company might save more if

it retired the units in 2021, even if only a little, “the Company must balance the

needs of the workforce and the communities that serve Karn Units 1&2 when those

units are retired.” (Id., quoting 9 TR 2685–2686.) And Mr. Heidemann said that

“[t]he 2023 retirement date allows the Company additional time to transition when

the units retire.” (9 TR 2686.)

MCV argues the Company’s retirement analysis was flawed because it did

not use the AEO gas forecast as required in the MIRPP. Instead, the Company

used its own Business as Usual (BAUCE) forecast. (MCV’s Exceptions, p 5.) Staff

does not agree that the Commission has required Consumers to use the AEO gas

26

forecast. The Medium 4 retirement analysis included in this IRP was to be “a

standalone analysis of various retirement scenarios for D.E. Karn Units 1 and 2 and

J. H. Campbell Units 1 and 2.” In re Consumers Energy Co’s 2017 Rate Case, MPSC

Case No. U-18322, 3/29/2018 Order, p 130. The Commission required the Company

to address the following topics in its analysis:

(1) capacity replacement costs; (2) impact of recovery of undepreciated book value; (3) customer rate impact analysis; (4) non-economic variables such as portfolio balance, employment,

and community impact; (5) effect on contractual fuel obligations; (6) near-term revenue requirements; (7) conditions of existing equipment; and (8) execution risk. [Id. at 23.]

The Commission did not specify what gas price to use in this analysis. The gas

price forecast used by the Company is reasonable, (9 TR 2628), and it complies with

the March 29, 2018 Order in Case No. U-18322.

The MIRPP adds other requirements for retirement analyses beyond the

standalone requirements for Consumers listed above. See In re Section 6t(1) of 2016

PA 341, MPSC Case No. U-18418, 11/21/2017 Order, Exhibit A. But these

requirements are generally flexible, allowing the Company to use age assumptions,

public announcements, or economics within the model. The emerging technology

scenario in the MIRPP also specifies that “Company-owned resource retirements

may be defined by the utility, however, meaningful analysis of whether coal units

should retire ahead of business as usual dates should be performed.” In re Section

27

6t(1) of 2016 PA 341, MPSC Case No. U-18418, 11/21/2017 Order, Exhibit A, p 18.

An AEO natural gas price forecast is not required for this “meaningful analysis.”

Consumers has met the criteria for retirement analyses set forth in Case No.

U-18322 and the MIRPP. MCV’s argument that the Company used the wrong gas

price is just a small piece of the overall retirement analysis. Company witness

Thomas Clark discussed several non-modeling considerations that favor retirement,

(7 TR 887–900), and Staff agrees that these should be considered and that they

support early retirement.

Response to the Solar Energy Industries Association (SEIA)

SEIA reiterates its argument that Consumers has “a capacity need that

obligates it to make full capacity payments to QFs beyond the 150 MW previously

required by the Commission.” (SEIA’s Exceptions, p 8.) Specifically, SEIA argues

that “the Commission should find that Consumers has a capacity need of no less

than 80 ZRCs [zonal resource credits].” (Id. at 8–9.) In its plan, as filed, Consumers

estimated that it had a surplus of 183 ZRCs in 2023. (6 TR 256, Figure 5.)

Removing the 157 ZRCs from the surplus for the Filer City PPA that FERC refused

to recertify as a qualifying facility, (6 TR 274), 50 ZRCs for solar in the Company’s

Renewable Energy Plan that the Commission deferred to this case, (6 TR 253), and

56 ZRCs for the CVR that the ALJ recommended excluding from the IRP leaves the

Company with the 80 ZRC deficit SEIA referenced.

28

Consumers witness Richard Blumenstock confirmed that the Company is no

longer moving forward with the Filer City PPA expansion, (6 TR 276), so Staff does

not dispute that this capacity has become available for the Company to fill through

other resources. As for the 50 ZRCs of solar in the Company’s Renewable Energy

Plan, the Commission “reserve[ed] its determination regarding the solar projects

until the final order in the IRP.” In re Consumers Energy Co’s 2017 Application to

Amend its Renewable Energy Plan, MPSC Case No. U-18231, 2/7/19 Order, p 28.

Doing so, it said, “will allow the Commission to evaluate the proposed solar

generation in a more complete context of the company’s long-term energy and

capacity needs, as well as alternatives such as third-party ownership that may be a

more cost-effective means of RPS compliance for this resource.” Id. If the

Commission does not approve the 50 ZRCs of solar in this case, Staff further agrees

that these ZRCs are available for the Company to fill through other resources.

Staff’s position on Consumers’ proposed CVR program has not changed. Staff

supports approval of the CVR program in this IRP along with preapproval of

$8,924,600 in capital expenditures for this program. (9 TR 2555–2556.) If, however,

the Commission were to exclude CVR from the Company’s plan, it would open up

additional ZRCs. But regardless of the amount of capacity that is removed from the

Company’s plan, the Company should be given an opportunity to respond to any

revisions to its preferred course of action before determining its capacity need.

Once its capacity need is finalized, the Company should use its proposed

competitive-bidding process to slowly secure additional supply- and demand-side

29

resources in small increments that will allow the Company to adapt as

circumstances change.

Conclusion

Staff encourages the Commission to approve Consumers’ IRP with the

changes that Staff has recommended throughout the course of this proceeding.

Respectfully submitted, MICHIGAN PUBLIC SERVICE COMMISSION STAFF

Spencer A. Sattler (P70524) Heather M.S. Durian (P67587) Amit T. Singh (P75492) Daniel E. Sonneveldt (P58222) Assistant Attorneys General Public Service Division 7109 W. Saginaw Hwy., 3rd Floor Lansing, MI 48917 Telephone: (517) 284-8140

DATED: March 11, 2019

20165 (E-P) CECo 2018-0222865-A\20165 p Replies to Exceptions (2).docx

STATE OF MICHIGAN

BEFORE THE MICHIGAN PUBLIC SERVICE COMMISSION In the matter of the application of CONSUMERS ENERGY COMPANY Case No. U-20165 for approval of an integrated resource plan (e-file paperless) under MCL 460.6t and for other relief. /

PROOF OF SERVICE STATE OF MICHIGAN ) ) ss COUNTY OF EATON ) De Ann Payne, being first duly sworn, deposes and says that on March 11, 2019, she served a true copy of the Michigan Public Service Commission’s Replies to Exceptions upon the following parties via e-mail only: Consumers Energy Company Anne M. Uitvlugt Robert W. Beach Bret Totoraitis Gary A. Gensch, Jr. Michael C. Rampe Theresa A.G. Staley Ian F. Burgess Consumers Energy Company One Energy Plaza Jackson, MI 49201 anne.uitvlugt@cmsenergy.com robert.beach@cmsenergy.com bret.totoraitis@cmsenergy.com gary.genschjr@cmsenergy.com michael.rampe@cmsenergy.com theresa.staley@cmsenergy.com ian.burgess@cmsenergy.com mpsc.filings@cmsenergy.com

Administrative Law Judge Hon. Sharon L. Feldman Administrative Law Judge 7109 W Saginaw Hwy., 3rd Floor Lansing, MI 48917 feldmans@michigan.gov

2

Consumers Energy Company Anne M. Uitvlugt Robert W. Beach Bret Totoraitis Gary A. Gensch, Jr. Michael C. Rampe Theresa A.G. Staley Consumers Energy Company One Energy Plaza Jackson, MI 49201 anne.uitvlugt@cmsenergy.com robert.beach@cmsenergy.com bret.totoraitis@cmsenergy.com gary.genschjr@cmsenergy.com michael.rampe@cmsenergy.com theresa.staley@cmsenergy.com mpsc.filings@cmsenergy.com

Michigan Environmental Council Christopher M. Bzdok Lydia Barbash-Riley 420 E. Front Street Traverse City, MI 49686 chris@envlaw.com kimberly@envlaw.com karla@envlaw.com lydia@envlaw.com Energy Michigan, Inc. Laura A. Chappelle Timothy J. Lundgren 201 N. Washington Square, Suite 910 Lansing, MI 48933 lachappelle@varnumlaw.com tjlundgren@varnumlaw.com

Environmental Law & Policy Center, Ecology Center, Union of Concerned Scientists & Vote Solar Margrethe K. Kearney Environmental Law & Policy Center 1514 Wealthy St. SE, Suite 256 Grand Rapids, MI 49506 mkearney@elpc.org

Cadillac Renewable Energy, LLC; Genesee Power Station, LP; Grayling Generating Station, LP; Hillman Power Company, LLC; TES Filer City Station, LP; Viking Energy of Lincoln, Inc; Viking Energy of McBain, Inc. Thomas J. Waters Anita G. Fox Fraser Trebilcock Davis & Dunlap, PC 124 Allegan Street, Suite 1000 Lansing, MI 48933 twaters@fraserlawfirm.com afox@fraserlawfirm.com

Michigan Chemistry Council & Solar Energy Industries Association Toni L. Newell Varnum Law Firm 333 Bridge Street, NW Grand Rapids, MI 49504 tlnewell@varnumlaw.com

3

Michigan Electric Transmission Company Richard J. Aaron Courtney Kissel Dykema Gossett, PLLC 201 Townsend Street, Suite 900 Lansing, MI 48933 raaron@dykema.com ckissel@dykema.com Michigan Energy Innovation Business Council & Institute for Energy Innovation Laura A. Chappelle Varnum Law Firm 201 N. Washington Square Suite 901 Lansing, MI 48933 lachappelle@varnumlaw.com Toni L. Newell 333 Bridge Street, NW Grand Rapids, MI 49504 tlnewell@varnumlaw.com Residential Customer Group & Great Lakes Renewable Energy Association Don L. Keskey Brian W. Coyer Public Law Resource Center PLLC University Office Place 333 Albert Avenue, Suite 425 East Lansing, MI 48823 donkeskey@publiclawresourcecenter.com bwcoyer@publiclawresourcecenter.com

Cypress Creek Renewables, LLC Jennifer Utter Heston Fraser Trebilcock Davis & Dunlap, P.C. 124 W. Allegan, Suite 1000 Lansing, MI 48933 jheston@fraserlawfirm.com Michigan Attorney General Celeste R. Gill Assistant Attorney General P. O. Box 30755 Lansing, MI 48909 gillc1@michigan.gov ag-enra-spec-lit-@michigan.gov Midland Cogeneration Venture, LP Jason Hanselman John A. Janiszewski Dykema Gossett, PLLC 201 Townsend Street, Suite 900 Lansing, MI 48933 jhanselman@dykema.com jjaniszewski@dykema.com Independent Power Producers Coalition of Michigan Timothy Lundgren Laura A. Chappelle Varnum Law Firm 201 N. Washington Square Suite 910 Lansing, MI 48933 lachappelle@varnumlaw.com tjlundgren@varnumlaw.com Association of Businesses Advocating Tariff Equity Michael J. Pattwell Bryan A. Brandenburg Clark Hill, PLC 212 E Cesar E. Chavez Avenue Lansing, MI 48906 mpattwell@clarkhill.com bbrandenburg@clarkhill.com

4

Sierra Club Michael Soules 1625 Mass Ave, NW, Ste702 Washington, DC 20036 msoules@earthjustice.org

Invenergy Renewables LLC. Nolan J. Moody Brandon C. Hubbard Dickinson Wright 215 S. Washington Sq., Suite 200 Lansing, MI 48933 nmoody@dickinsonwright.com bhubbard@dickinsonwright.com

Energy Michigan, Inc. Laura A. Chappelle Timothy J. Lundgren 201 N. Washington Square, Suite 910 Lansing, MI 48933 lachappelle@varnumlaw.com tjlundgren@varnumlaw.com

Michigan Environmental Council Christopher M. Bzdok Lydia Barbash-Riley 420 E. Front Street Traverse City, MI 49686 chris@envlaw.com kimberly@envlaw.com karla@envlaw.com lydia@envlaw.com

________________________________________

De Ann Payne

Subscribed and sworn to before me this 11th day of March, 2019. _________________________________ Pamela A. Pung, Notary Public State of Michigan, County of Clinton Acting in the County of Eaton My Commission Expires: 05-07-2025