in Re Application of Dte Electric Company to Increase Rates

If this opinion indicates that it is “FOR PUBLICATION,” it is subject to
revision until final publication in the Michigan Appeals Reports.
STATE OF MICHIGAN
COURT OF APPEALS
In re Application of DTE ELECTRIC COMPANY
to Increase Rates.
DTE ELECTRIC COMPANY, UNPUBLISHED
February 25, 2021
Petitioner-Appellant,
V No. 349924
Public Service Commission
MICHIGAN PUBLIC SERVICE COMMISSION, LC No. 00-020162
ASSOCIATION OF BUSINESSES ADVOCATING
TARIFF EQUITY, and RESIDENTIAL
CUSTOMER GROUP,
Appellees,
and
MICHIGAN ENVIRONMENTAL COUNCIL,
Intervening Appellee.
In re Application of DTE ELECTRIC COMPANY
to Increase Rates.
RESIDENTIAL CUSTOMER GROUP,
Appellant,
V No. 350008
Public Service Commission
MICHIGAN PUBLIC SERVICE COMMISSION, LC No. 00-020162
MICHIGAN CABLE TELECOMMUNICATIONS
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ASSOCIATION, and ASSOCIATION OF
BUSINESSES ADVOCATING TARIFF EQUITY,
Appellees,
and
DTE ELECTRIC COMPANY,
Petitioner-Appellee.
Before: M.J. KELLY, P.J., and RONAYNE KRAUSE and REDFORD, JJ.
PER CURIAM.
This matter arises in part out of a request by petitioner-appellant DTE Electric Company
(DTE) to increase its retail electricity rates for the purpose of recouping the cost of various
upgrades performed to its River Rouge power plant, which is scheduled to be retired in the near
future. DTE contends that the upgrades were necessary to ensure the plant’s safe operation. In
addition, DTE sought to recoup the cost of its deployment of 300 advanced metering infrastructure
(AMI), or “smart meters.” In Docket No. 349924, DTE appeals by right the decision of the
Michigan Public Service Commission (PSC) that, in relevant part, disallowed the above requested
recoupments. In Docket No. 350008, appellant Residential Consumer Group (RCG) appeals of
right a different portion of the same order, generally asserting that the PSC committed a number
of legal errors pertaining to the “test year” used for calculating DTE’s rates, the applicability of
changes in federal tax laws, and the extent to which the PSC permitted DTE to charge for its smart
meters. We vacate the PSC’s order as to the amount of its disallowance for the 300 smart meters,
and we remand for the PSC to reconsider that allowance. In all other respects, we affirm.
I. STANDARDS OF REVIEW
A final order of the PSC must be authorized by law and be supported by competent,
material, and substantial evidence on the whole record. Const 1963, art 6, § 28; In re Consumers
Energy Co, 279 Mich App 180, 188; 756 NW2d 253 (2008). “ ‘Substantial evidence’ is evidence
which a reasoning mind would accept as sufficient to support a conclusion. While it consists of
more than a scintilla of evidence, it may be substantially less than a preponderance.” Tomczik v
State Tenure Comm, 175 Mich App 495, 499; 438 NW2d 642 (1989).
A party aggrieved by an order of the PSC has the burden of proving by clear and convincing
evidence that the order is unlawful or unreasonable. MCL 462.26(8). To establish that a PSC
order is unlawful, the appellant must show that the PSC failed to follow a statutory requirement or
abused its discretion in the exercise of its judgment. In re MCI Telecom Complaint, 460 Mich
396, 427; 596 NW2d 164 (1999). A reviewing court “gives due deference to the PSC’s
administrative expertise and is not to substitute its judgment for that of the PSC.” Attorney General
v Pub Serv Comm No 2, 237 Mich App 82, 88; 602 NW2d 225 (1999).
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Issues of statutory interpretation are reviewed de novo. In re Complaint of Rovas, 482
Mich 90, 102; 754 NW2d 259 (2008). A reviewing court should give respectful consideration to
an administrative agency’s interpretation of statutes it is obliged to execute, but not deference. Id.
at 108.
II. RIVER ROUGE ELECTRIC GENERATING UNIT 3
DTE Energy operates, inter alia, the River Rouge power plant, a two-generator coal-
powered plant. One of the generators was retired in 2016, and the other is scheduled for retirement
in the near future. DTE expended significant amounts of money operating and maintaining (O&M)
the plant, and it also expended significant amounts of money performing some upgrades that it
contends are to ensure the plant’s safe operation. The PSC permitted DTE to recover $17.65
million in O&M costs. However, the PSC disallowed a further “$8.45 million in past capital
expense and $1.87 million in future capital expense.” DTE argues that the PSC erred by
disallowing recovery of those capitalized maintenance expenses. We disagree.
As an initial matter, it is important to understand that as a general matter, costs expended
by an entity may be treated as “expensed” or “capitalized.” Capitalized costs ordinarily entail the
acquisition of some tangible asset, or doing something to that tangible asset that significantly
increases its usefulness or expected operating life. In contrast, expensed costs ordinarily entail
routine and expected maintenance for the purpose of keeping an asset operating normally for its
expended lifespan. The significance is that public utilities are, very generally, permitted to make
a profit from the combined value of the utility’s assets; the combined value of those assets is called
the utility’s “rate base.” Utilities are also permitted to directly recoup, dollar-for-dollar, the actual
cost of their operating expenses. Whether a particular cost is “capitalized” or “expensed” is
significant, because ratepayers pay for both, but ratepayers also pay for a utility to make a profit
from anything “capitalized.” Thus, it is important that DTE sought to recoup the cost of its
upgrades to the River Rouge plant as what it calls “capitalized maintenance expenses,” which
would have the effect of increasing its rate base, rather than as ordinary operating expenses.
The PSC observed that DTE had sought to recover expenses of the sort here at issue over
the course of cases preceding the instant one:
In the December 11, 2015 order in Case No. U-17767, the Commission
disallowed capital costs associated with environmental retrofits for Unit 3 because
they were not shown to be cost effective. In the January 31, 2017 order in Case
No. U-18014, the Commission again disallowed capital costs for Unit 3. In that
order, the Commission found that the utility had decided to permanently shut down
River Rouge Unit 2 but had not updated any of the assumptions in the [net present
value revenue requirement (NPVRR) analysis] for Unit 3, despite knowing that
Units 2 and 3 shared many costs; thus, again failing to show that the capital
expenditure was cost effective (the Commission allowed O&M costs). In the 2018
orders, the Commission again disallowed capital costs for Unit 3 based on the
continued failure of the utility to update the NPVRR and its entire analysis of Unit
3 with a showing of clear cost effectiveness, but allowed O&M costs. [In re
Application of DTE Electric Co to Increase Rates, order of the Public Service
Commission, entered May 2, 2019 (Case No. U-20162), p 11 (citations omitted)].
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A. EVIDENCE
Matthew Paul, DTE’s Vice President of Fossil Generation Plant Operations, testified that
although the River Rouge plant was scheduled for retirement in the near future, it still accounted
for a non-trivial amount of electrical generation and demand response. As a consequence, it
remained important to keep the plant in safe and reliable operating condition to ensure that the
electric grid remained stable. He explained that a number of pumps, motors, valves, instruments,
and control system components had been replaced for that purpose. The single largest expenditure
was reconstruction of part of the Reheat and Intercept Stop Valves. If those valves failed during
a generator shutdown, it could result in the turbine exploding with the possibility of injury or loss
of life as well as extensive property damage.
Testimony was also introduced regarding cost analysis of the continued operation of the
River Rouge plant, as opposed to replacing it. These analyses are referred to as “NPVRR,” which
is an analysis of the revenue an existing plant needs to bring in to offset its ongoing expenses and
initial investment; and “CONE,” which is the amount of revenue that a newly-constructed power
plant would need to bring in to offset both its ongoing operating expenses and the annualized cost
of its construction. Irene Dimitry, Vice President of Business Planning and Development with
DTE Energy Corporate Services, LLC, a subsidiary of DTE, concluded that its NPVRR analysis
for River Rouge unit 3 showed a “range from $15 million more costly to $10 million less costly to
customers to maintain” its current scheduled retirement, dependent upon which costs of fuel
assumptions were made. Avi Allison, a senior associate with a research and consulting firm
specializing in electricity industry regulation and planning, testified on behalf of the Michigan
Environmental Council (MEC) that continuing to operate the River Rouge plant would financially
benefit customers only by assuming a worst-case scenario. Allison additionally noted that DTE
had made a mistake in calculating its fuel costs. The PSC concluded that after correcting the latter
irregularity, ratepayers would benefit from early retirement of the River Rouge plant under all
scenarios.
B. THE DECISION BELOW
The administrative-law judge (ALJ) summarized the history of this issue, and explained as
follows in the proposal for decision:
It has been over three years now since DTE Electric was first put on notice that the
economics of operating the River Rouge units had been called into question. The
issue became more pronounced in 2016, when [River Rouge Unit 2] retired, leaving
previously shared costs to be borne by RR 3 only. Because the company chose not
to update its case and present a new NPVRR for RR 3 alone, the Commission
deferred the company’s proposed capital costs. Then in 2017, DTE Electric again
failed to update its analysis of the continued operation of RR 3 and the Commission
again deferred cost recovery.
Through the testimony of Mr. Allison . . . , [the MEC and other intervenors]
convincingly showed that the economics of operating RR 3 until the end of the test
year is more likely than not to be detrimental to ratepayers and that there is
significantly greater benefit to retiring the unit in December 2018. After correcting
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DTE Electric’s error in its NPVRR analysis, and even using the 50% of CONE
scenario, the net benefit of 2018 retirement is still $8 million, whereas under the
100% of CONE price forecast, the net benefit of a 2020 retirement date is only $5
million. . . . Meanwhile, the forecasts for 2019 and 2020 do not appear to
demonstrate any issues with available capacity . . . .
The ALJ thus opined that “routine capital costs totaling $1.87 million for 2019 through the end of
the test year are not reasonable and prudent and should be disallowed,” and also that “O&M costs
for 2019 and the test year should also be disallowed on grounds that the record in this case
demonstrates that RR 3 could have, and should have, been retired at the end of 2018.”
The PSC agreed, explaining as follows:
The Commission sees no reason on this record to deviate from its prior
determinations. The Commission continues to agree with DTE Electric that while
the unit is in use, reasonable and prudent O&M costs should be approved to ensure
safe operation and a smooth transition to retirement. However, the updated
NPVRR provided on this record does not persuade the Commission to award the
2017-2018 capital costs to DTE Electric nor the future capital expense, because the
evidence is simply not conclusive on the issue of reasonableness and prudence. The
NPVRR does not make a convincing case that the 2017-2018 capital expense
amounts were prudent in comparison to shutting Unit 3 down in 2016, nor does it
make a convincing case that the bridge period and test year amounts make sense in
comparison to shutting the unit down earlier than 2020. The company made a
decision to continue to run Unit 3 and the unit must be run safely and in compliance
with all applicable environmental laws; thus, the Commission has continued to
approve O&M costs. But the decision to make capital investments in Unit 3 has
not been adequately supported from the beginning. [In re Application of DTE
Electric Co, order of the PSC entered May 2, 2019 (Case No. U-20162), pp 11-12.]
C. ANALYSIS
“A public utility has a right to a just and reasonable rate of return on its investment,” and
such utilities “are protected from being limited to rates that are confiscatory.” ABATE v Pub Serv
Comm, 208 Mich App 248, 269; 527 NW2d 533 (1994). Accordingly, “[a] public utility has a
substantive right, set forth in the statutes and rooted in the constitution, to rate relief where the
revenue produced by an existing rate structure is less than the amount required by the statutes or
the constitution.” Consumers Power Co v Pub Serv Comm, 415 Mich 134, 145; 327 NW2d 875
(1982) (citations omitted).
DTE argues that disallowing recovery of the capital maintenance expenses it requested for
River Rouge Unit 3 constituted confiscatory ratemaking, or an arbitrary denial of its right to
reasonable return, with respect to its costs involved in the continued operation of the facility
pending its retirement.
DTE suggests it was arbitrary for the PSC to approve recovery of ordinary maintenance
expenses while disallowing recovery of capital maintenance expenses, on the ground that the two
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kinds of expenses go hand in hand. However, as noted above and as explained by the PSC, a utility
“simply recoups” reasonable and prudent operation and maintenance expenses, but “capital
expenditures increase the rate base on which the utility earns a return,” such that the ratepayers
must bear the burden not only of covering the expenses, but also of providing a reasonable profit
on those investments. Thus, “[o]perating and maintenance expenses should not be capitalized
without a clear reason for doing so.”1 At issue in this case, then, is not only the reasonableness of
the maintenance costs at issue, but also DTE’s request to treat those costs as capitalized.
The record does not show that DTE ever made an alternative request to treat those cost as
ordinary, dollar-for-dollar recoupable expenses. Furthermore, even if DTE had done so, DTE’s
analysis of the reasonableness and prudence of those expenses is unduly narrow. Presuming the
costs were, in fact, necessary to ensure that the River Rouge plant remained safe to operate, this
overlooks whether it was reasonable and prudent to keep the River Rouge plant operating at all.
The PSC found that it had been imprudent for DTE not to retire and replace the River Rouge plant
earlier, instead of expending resources keeping it operational. Thus, it would follow that investing
significant resources into upgrading something that should have been retired would also be
unreasonable and imprudent. Because the PSC had a sufficient evidentiary basis for concluding
that such continued operation was not reasonable, DTE fails to show that the disallowance of the
recovery of capitalized maintenance expenses for it was unreasonable or arbitrary.
III. ADVANCED METERING INFRASTRUCTURE UPGRADE PROJECT
DTE argues that the PSC erred by refusing to authorize recovery of expenses related to
upgrading 300 customers from 3G to 4G2 AMI (or “smart meter”) technology, or, alternatively,
that the amount of the disallowance was excessive. We find DTE’s arguments concerning the
need to upgrade those 300 customers to 4G insufficiently persuasive, but we agree with DTE that
the PSC’s determination of the amount of the disallowance was not supported by the record.
The AMI program generally involves electrical meters transmitting energy consumption
information from customers in real time, so customers can make “live” changes to their energy use
for reasons such as reducing costs or reducing demands on the system. See In re Applications of
1
The PSC cites In re Application of DTE Electric Co to Increase Rates, order of the Public Service
Commission, entered December 11, 2015 (Case No. U-17767), in which the PSC approved funding
for DTE’s Enhanced Vegetation Management Program only in part, stating that it was “not
persuaded that this cost category is appropriate for capitalization,” because the activity was not
“fundamentally different from enhanced clearing, the costs of which have never been capitalized.”
Id. at p 17. In affirming the latter decision, this Court recognized that at issue was not the expense
of the program, but rather the capitalization of it, and deferred to the PSC’s selection of expert
testimony upon which to rely. In re Application of DTE Electric Co to Increase Rates, unpublished
per curiam opinion of the Court of Appeals, issued February 13, 2018 (Docket Nos. 331599,
331868, & 332159), p 5.
2
3G, 4G, and 5G refer to “generations” of incremental developments to radio transmission
technologies used primarily for cellphones, but also for other devices that communicate using
cellular networks.
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Detroit Edison Co, 296 Mich App 101, 114; 817 NW2d 630 (2012). In 2012, this Court was
unconvinced that the evidence in the record had adequately supported funding the project by
ratepayers. Id. at 114-116. More recently, this Court has been generally, if cautiously, supportive
of AMI programs. See In re Consumers Energy Co, 322 Mich App 480, 490-491; 913 NW2d 406
(2017); In re Application of Consumers Energy to Increase Elec Rates (On Remand), 316 Mich
App 231, 240; 891 NW2d 871 (2016); Detroit Edison Co v Stenman, 311 Mich App 367; 875
NW2d 767 (2015).
A. COMPLETION OF UPGRADES TO 4G
Brian Moccia, DTE’s Manager of the AMI Engineering Group in Electric Distribution
Operations, provided the following background information:
Since the completion of the pilot installation in 2008, the Company has been
steadily installing meters and modules. As of June 1, 2018, DTE Energy has
installed over 2.6 million electric meters . . . .
. . . [W]e are still working to complete the remaining 1,077 installments of
AMI electric meters in 2018.
. . . The Company has integrated all of the basic functions of AMI from
meter reading, reconnects, disconnects, and outage notifications to theft/tampering
investigation. . . . Reconnects and disconnects are being completed over the air and
within minutes as opposed to the former manual and field visit requirement.
Moccia further explained that AMI depended on cellular telecommunications networks, and the
cellular industry was in the process of migrating from 3G transmission technology to 4G
transmission technology. He expected that 3G would be phased out by late 2020, and as a
consequence, all AMI “cell relays” (CRs) that depended on 3G would either need to be upgraded
or would lose all remote capabilities, effectively destroying the benefits of the AMI program. He
testified that DTE had approximately 3,300 3G CRs and 6,000 industrial-customer 3G meters.
Thus:
Without this upgrade, DTE Electric will lose daily communication with
approximately 1 million of the 2.6 million DTE Electric residential electric meters
and communication to approximately 6,000 industrial meters. These meters will
not be remotely accessible which will have a significant negative impact on our
ability to bill customers, eliminate our ability to obtain critical power quality and
outage data; and remove our ability to remotely connect/disconnect meters after the
cellular carriers transition to 4G cellular.
Asked about bypassing 4G and moving directly from 3G to 5G, Moccia replied that “all parties
are expecting 4G devices to coexist within 4G and 5G infrastructure,” and that “5G products and
5G infrastructure is not readily available.”
However, a public utilities engineer from the Smart Grid Section of the Energy Operations
Division of the PSC reported that the recommendation of the PSC staff was “to disallow all costs
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associated with the additional relays over the 3,000 the Company initially installed as the
Company’s meter read rate through 2017 was 98.51%.” The witness elaborated:
While Staff understands that generally a higher read rate is better for
customers, in this case the Company is well above the Commission[’]s Service
Quality and Reliability Standard of 85% and the incremental costs required to
increase the read rate beyond the 98.51% the Company is already achieving are
unnecessary at this time. Due to the diminishing returns that can be achieved with
increasing its read rates further, the costs that will be required to further increase
the read rates are likely above and beyond the benefits that will be achieved and
were not supported in the Company’s direct case.
In the end, the PSC explained its decision to deny recovery for the proposed upgrades as
follows:
[T]he Commission . . . adopts the proposed $9.6 million disallowance associated
with the 300 additional 4G relays. . . . DTE Electric’s meter read rate is high, well
above the 85% required by the Commission’s Service Quality and Reliability
Standards for Electric Distribution Systems, Mich Admin Code, R 460.724(d). The
utility has been able to achieve this level of meter reads with 3,000 relays, and the
Commission agrees with the Staff that the additional 300 relays are an unnecessary
expense. . . . The Commission approves this disallowance. In DTE Electric’s last
rate case, the Commission expressed concern over the conversion to 4G given the
plans of the telecommunications industry to move to 5G and the potential for
stranded investments due to technology obsolescence. The Commission stresses
the importance for DTE Electric to strategically integrate and sequence its
technology enhancements to support grid modernization efforts. With increased
digitalization, this attention to technology is essential to avoid unnecessary costs
and ensure ratepayer benefits. . . . [In re Application of DTE Electric Co, order of
the PSC entered May 2, 2019 (Case No. U-20162), pp 34-35 (citation omitted).]
We conclude that the challenged decision was simply a judgment call, and that DTE has
failed to show that the PSC abused its discretion in the matter. We recognize that DTE has made
a reasonable argument that its customers with 3G would benefit from an upgrade to 4G, and the
PSC’s witness acknowledged that “a higher read rate is better for customers.” However, the PSC’s
witness also opined that DTE’s “read rate” was already very high, and a substantial investment to
further increase that rate offered poor value. Further, although DTE’s witness reported that
equipment for upgrading to 5G was not yet available, DTE’s brief on appeal includes no assertion
that problems with obtaining 5G equipment make it impractical to shift the 300 customers still at
3G directly to 5G in reasonable time.
For these reasons, DTE fails to show that the decision to disallow recovery of the costs of
upgrading 300 additional customers from 3G to 4G was not supported by substantial evidence, or
was an abuse of discretion.
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B. AMOUNT OF DISALLOWANCE
DTE argues that the entire project for upgrading 3,300 relays carried a total cost of $34.3
million, and that the 300 relays yet to be upgraded thus constituted approximately 9% of the total
proposed, but that the PSC’s $9.6 million disallowance was approximately a third of that total cost,
thus seriously out of proportion. DTE insists that the disallowance should have been no more than
$2,370,000.
In support of the latter calculation, DTE cites specific data from the record indicating that
the total cost of the project was $34.3 million. We note, however, that $2,370,000 is substantially
less than 9% of $34.3 million. DTE also cites testimony from its Director of Operational
Technology in Electric Distribution Operations, Jacqueline Robinson, who testified as follows:
I provided the cost breakdown of the 3G to 4G project. I stated that “There are
external contracts to provide network engineering design, project management, and
overhead line installation of approximately $3.5 million, and DTE labor of
approximately $5 million. The material for the project is the largest contributor of
almost $26 million.” The material cost of the project represents a turn key solution
with a hardware vendor. This represents the cost of the hardware, most of the
installation labor, and material. The $26 million divided by 3,300 cellular relays
results in a per relay cost of approximately $7,900. Therefore, even if Staff
recommended disallowing adding 300 relays, the disallowance should only be
$2,370,000 (300 times $7,900).
It appears that Robinson’s $26 million figure omits the $3.5 million in contract labor costs and $5
million in DTE’s labor costs. However, adding those labor costs comes to $34.5 million, only
slightly more than the $34.3 million total project cost cited by DTE in its brief on appeal. Dividing
the total including labor costs by 3,300 units results in a per-unit cost of $10,454.5, and at 300
units, the total disallowance amount would be $3,136,365.
The PSC’s only explanation for rejecting DTE’s proposed amount of disallowance was that
its staff’s proposed disallowance included the cost of labor while DTE’s proposal did not. As
noted, this is technically true: the total disallowance amount including labor costs of $3,136,365
is significantly greater than the $2,370,000 cited by DTE. However, the PSC instead adopted a
disallowance of $9.6 million, which is a vastly greater amount; and, importantly, the PSC provided
no explanation in its May 2, 2019, order of why such an amount was appropriate. Indeed, the
PSC’s staff admitted, in response to DTE’s motion for reconsideration, that the $9.6 million figure
was incorrect, stating:
Staff points to its initial brief for the proper calculation of the disallowance
for the 300 additional relays at issue. Staff’s brief provides,
Staff reasserts that its calculation of its disallowance is correct given
the information that the Company provided in the instant case. Staff
used the $6,000 per cell relay shown in CSM-8.7 to calculate that
the Company should have $18,000,000 in costs to purchase the cell
relays. Staff then took this number from the $26,000,000 in material
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costs shown in Staff’s Exhibit S-20, resulting in a disallowance of
$8,000,000. In calculating the installation costs, Staff took the
Company’s proposed installation cost of $5,000,000 and calculated
a cost per relay to install totaling $1,515. Staff then took that cost
and multiplied it by the 300 cell relays it is recommending for
disallowance and found that value to be $454,500. Staff’s
calculations are based on the information the Company provided in
audit response and is the best information that was made available
to Staff.
Therefore, Staff maintains that the proper disallowance for this category should be
$8,454,500, which is the sum of staff’s material cost disallowance and installation
cost disallowance. Staff maintains that neither the Company’s proposed $2.37
million disallowance calculated in its Petition, nor the $9.6 million disallowance
referenced in the May 2, 2019 order are correct.
The PSC’s staff thus still arrived at a much greater amount than did DTE, but the staff’s
recalculation was at least explained. The recalculation also significantly undermined the PSC’s
reliance on its staff for the $9.6 million figure. The PSC nevertheless denied DTE’s motion for
reconsideration, stating that its staff “opposes the petition on grounds that the utility’s arguments
were addressed by the Commission, while advocating for a different disallowance amount which
appeared in the Staff’s initial brief but not on the record,” and that “all of DTE Electric’s
arguments, including those addressing the disallowance amount, were addressed in the May 2
order.” The PSC never provided a substantive explanation for rejecting its staff’s reduced
calculation or for its $9.6 million disallowance. The PSC has thus failed to show that its figure
was supported by substantial evidence on the whole record.
Conversely, DTE asserts that the staff’s new figure was “based on an unexplained
calculation,” but it offers no discussion of the particulars quoted above from the staff’s original
brief. Thus, DTE has not presented any concrete explanation of why the staff’s numbers are
unfounded or why the staff’s arithmetic is erroneous. We therefore decline to merely adopt DTE’s
alternative figure. Rather, we hold that the PSC’s disallowance of $9.6 million is unsupported, but
that the PSC correctly found DTE’s alternative proposed amount is also inappropriate. We will
not substitute our judgment for that of the PSC by purporting to calculate a more appropriate
disallowance amount on our own. See Attorney General, 237 Mich App at 88. Instead, we vacate
the May 2, 2019, order as to the amount of disallowance for DTE’s 4G upgrade to the 300
additional relays, and we remand this case to the PSC with instructions to review the whole record
and decide again the amount of the disallowance while providing a reasonably detailed explanation
of the basis for it.
IV. PROJECTED TEST YEAR
RCG argues that the PSC erred by allowing DTE, for purposes of establishing
representative levels of revenues, expenses, rate base, and capital structure for use in the rate-
setting formula, to designate a projected test year that extended beyond 12 months after it filed this
rate case. We disagree.
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A “test year” is a utility rate-making conceptual tool that involves selecting a given period
of time, usually 12 months, and tallying up all of the utility’s costs, assets, expenses, income,
entitlement to profit from its rate base, and, broadly, other moneys in and out. Oftentimes, some
adjustments will be made to account for particular circumstances or expectations. This adjusted
tallying-up will then, in principle, reveal either a revenue deficiency permitting rates to be
increased, or a revenue surplus requiring rates to be decreased. In this case, DTE relied on a
projected (i.e., anticipated future) test year from May 1, 2019, through April 30, 2020. Also
factoring into its calculations was the historical year consisting of the 12 months ending December
31, 2017.MCL 560.6a(1) authorizes a utility to “use projected costs and revenues for a future
consecutive 12-month period in developing its requested rates and charges.”
RCG argues that MCL 560.6a(1), the statute authorizing the use of test years, does not
permit utilities to utilize test years set more than 12 months into the past or 12 months into the
future, as measured from the date on which a rate case is filed. RCG’s interpretation of the statute
is contrary to the statute’s plain language. In relevant part, the statute provides as follows:
A gas utility, electric utility, or steam utility shall not increase its rates and charges
or alter, change, or amend any rate or rate schedules, the effect of which will be to
increase the cost of services to its customers, without first receiving commission
approval as provided in this section. . . . A utility may use projected costs and
revenues for a future consecutive 12-month period in developing its requested rates
and charges. . . .
There is no dispute that the second quoted sentence above authorizes the use of test years. The
plain language of the second quoted sentence, as the PSC found, authorizes the use of test years
consisting of “consecutive 12-month periods.” In other words, a utility may not utilize a test period
consisting of, for example, 11 months or 13 months. Nowhere in the statute is any express or
implied constraint upon when that 12-month period must be set.
RCG argues that such an interpretation would permit test years to be set too far in the future
or in the past to be useful. We agree that no such constraint exists in the statute. However, a utility
that selects a test year set too far in the past or future would obviously risk rejection by the PSC,
and doing so would likely make adjustments prohibitively difficult. Any adoption by the PSC of
such an inappropriate test year would also be subject to appellate challenges for unreasonableness.
See MCL 462.26(8); In re MCI Telecom Complaint, 460 Mich at 427. Furthermore, even if we
agreed with RCG’s argument that, in effect, the lack of a constraint on when a utility may set a
test year could lead to an absurd result, which we do not, we may not disregard the plain language
of the statute. Taylor v Lansing Bd of Water and Light, 272 Mich App 200, 207; 725 NW2d 84
(2006). Rather, the “absurd result” rule permits judicial construction to avoid an absurdity only if
a statute has already been determined to be ambiguous. Id. Even if we were at liberty to depart
from the plain language of the statute, we would not do so here, because RCG has failed to show
that its concerns have any practical foundation.
RCG argues that its reading of MCL 460.6a(1) is properly based on the plain language of
related statutory provisions. Related statutes should be read in pari materia, with the goal of
harmonizing those statutes in furtherance of their common purpose. Jennings v Southwood, 446
Mich 125, 136-137; 521 NW2d 230 (1994). However, “the in pari materia doctrine is a rule of
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statutory construction that is not implicated if the language of the statute is unambiguous and the
legislative intent is clearly expressed.” City of Grand Rapids v Brookstone Capital, LLC, ___
Mich App ___, ___; ___ NW2d ___ (2020) (Docket No. 350746), slip op at pp 3-4. RCG cites
other statutory provisions that impose constraints on when the PSC must issue a final order and on
how frequently rate cases may be filed. Neither provision compels the conclusion that the
Legislature must have omitted a temporal constraint from MCL 560.6a(1) due to a scrivener’s
error or otherwise offers a compelling reason why we should consider the plan language of the
statute to be in error.
We reject RCG’s challenge to the prospective test year adopted in this case.
V. THE TAX CUTS AND JOBS ACT OF 2017
RCG argues that the PSC failed to properly take into account the reduction in the federal
corporate income tax rate occasioned by Tax Cuts and Jobs Act of 2017 (TCJA).3 We are not
persuaded.
In response to the enactment of the TCJA, the PSC commenced Case No. U-18494,
generally for the purpose of determining how any savings enjoyed by utilities as a result of the
TCJA should be passed on to ratepayers. In relevant part, the PSC adopted a “Credit A,” which
was a “going-forward tax credit” intended to pass utilities’ income-tax savings on to customers as
quickly as possible. Credit A was intended to be a temporary measure, implemented on an
exceptional basis outside the normal rate-making cycle, and to last only until utilities’ rates were
updated pursuant to that normal process. Credit A was to be determined on a utility-by-utility
basis in contested cases. Credit A went into effect on January 1, 2018. Relevant to this matter,
the “Credit A” case involving DTE concluded with the parties’ agreement that the forward-looking
credit associated with the tax reduction was $156.9 million. The PSC approved the settlement,
and approved tariffs implementing that rate reduction effective on August 1, 2018.
In the meantime, however, DTE filed its application in this case on July 7, 2018; in other
words, after Credit A went into effect in general, but before Credit A was actually approved and
implemented as to DTE. DTE explains that when it filed its application in this case, it “accounted
for the TCJA’s reduction in the applicable federal income tax rate from 35% to 21% effective
January 1, 2018; however, it did not account for the Credit A refund because the Credit A rate
reduction had not yet occurred.” The PSC agrees that DTE updated its rates for the projected test
year to reflect the tax rate reduction, but, “because the Credit A had not yet been approved when
DTE filed the present case, the Company did not account for the credit’s impact.”
DTE’s Manager of Revenue Requirements explained that application of the Michigan
Business Income Tax, Municipal Income Tax, and Federal Income Tax in 2017 required DTE “to
collect $1.6393 in revenue to produce $1.00 of after-tax income.” As a consequence of the TCJA’s
tax reduction, the amount of revenue then needed to produce $1.00 of after-tax income was reduced
to $1.3496. In other words, DTE needed to take in less revenue (i.e., less money from ratepayers)
3
See PL 115-97; 131 Stat 2054.
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to generate the same amount of income. A Departmental Analyst in the Rates and Tariff Section
of the PSC’s Regulated Energy Division explained that DTE’s Credit A approval decreased DTE’s
revenues by “approximately $148.2 million.” The PSC ultimately authorized DTE to adopt new
rates calculated to cover, among other things, “a jurisdictional revenue deficiency of $125,097,000,
combined with the expiration of the Tax Cuts and Jobs Act of 2017 Credit A of $148,237,000.”
In re Application of DTE Electric Co, order of the PSC entered May 2, 2019 (Case No. U-20162),
p 212. Earlier in that order, the PSC noted that DTE has variously “supported a revised revenue
deficiency of $250.2 million . . . and . . . $248.6 million,” neither of which “include[d] the rate
effect of the expiration of the Tax Cuts and Jobs Act of 2017 Credit A of $148.237 million,
authorized in the July 24, 2018 order in Case No. U-20105,” the inclusion of which “brings the
original request to $476 million.” Id. at 1 n 1.
RCG expressly agrees that the PSC’s order in this case terminated DTE’s Credit A
reduction, and further that the value of that reduction is $148,237,000. Rather, RCG argues that
the federal tax reduction would simultaneously reduce DTE’s revenues and expenses by the same
amount, and that because the “Credit A Order simply reduced rates to reflect the corresponding
reduction in DTE’s federal income tax expense,” termination of Credit A “should have been totally
neutral in terms of rate impact.” RCG thus concludes that DTE received a windfall of
approximately $148.2 million laundered into its rates. However, we agree with the PSC’s
explanation of what actually happened: “DTE’s initial rate request already took the TCJA’s tax
reduction into account. The Credit A refund arose after that, so it had to be adjusted back out.” In
other words, DTE corrected for the effect of the TCJA in its rate application, and the subsequent
approval of Credit A resulted in a double correction. What RCG appears to regard as a windfall
was, in fact, elimination of double-dipping. In other words, the PSC did not increase DTE’s rates
by $148.2 million, but rather adjusted the rates to reflect that they had already been reduced by
that amount. We reject this claim of error.
VI. ADJUSTMENTS FOR EARLIER VIOLATIONS
RCG argues that the PSC abused its discretion by declining to adjust DTE’s rates in this
case to include enforcement of an earlier settlement and order. We disagree.
In its brief on appeal, RCG presents a detailed history of earlier proceedings concerning
purportedly non-transmitting AMI meters that were in fact sending radio signals, which culminated
in a 2018 order of the PSC approving a settlement agreement. The proposal for decision in this
case reported as follows:
On December 20, 2018, the Commission issued an order in Case Nos. U-
20084 and U-18486 approving a contested settlement agreement. Among other
things, the settlement agreement provides:
DTE Electric agrees to replace the meters of all electric customers
currently electing service under the Company’s Non-Transmitting
Meter Provision, with digital meters that are not capable of
transmitting any signals. DTE Electric will complete the
replacement by December 2019, provided that the opt-out customers
grant the Company access to facilitate the replacement. Before
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replacing an electric opt out customer’s meter, DTE Electric will test
the existing meter to determine if the radios are enabled and/or
broadcasting. If the on-site tests, or other information available to
DTE Electric, indicate that either one of the radios in the opt out
customer’s meter is still sending a signal, all monthly opt-out fees
paid to date by the customer will be refunded including interest per
the Billing Rules. No fee will be assessed to the opt-out customer
for the meter replacement and DTE Electric will record a one-time
credit as Contribution in Aid of Construction in the amount of
$750,000 to offset the installation costs of the digital meters. The
remaining current customers that do not have an AMI meter, and
who elect to take service under DTE Electric’s Non-Transmitting
Meter Provision will receive digital . . . nontransmitting meters.
DTE shall prepare quarterly reports on the progress of the meter
replacement.
RCG argued that DTE’s rates should be adjusted downward to reflect the costs incurred by DTE
to remedy its violations as addressed in the settlement agreement. The ALJ and the PSC both
concluded that the settlement agreement was not approved until after the record in this matter had
closed, and if DTE’s rates should be adjusted as a consequence of the settlement agreement, any
such adjustment should be addressed in DTE’s next rate case.
RCG notes that the order underlying this case was issued after the settlement order in
question, and asserts that the investigation underlying the latter took place at the same time as
proceedings in this case, and also that DTE incurred expenses in order to “undertake countless
hours of company time to investigate the situation, render refunds to opt-out customers, to
formulate reports to the Commission, to litigate issues in U-20084, and to engage in settlement
meetings, among a host of other activities.” However, RCG neither identifies anything in the
record below suggesting that DTE requested that the new rates cover any such expenses, let alone
that the PSC authorized such recovery; nor explains why future rate cases will not adequately
provide opportunities for appropriate adjustments.
As a result, we reject this claim of error.
VII. SMART PHONE OPT-OUT CHARGES
RCG argues that the PSC erred by continuing to recognize AMI opt-out charges as
established in earlier proceedings. Again, we disagree.
Specifically, DTE imposes extra charges on customers who, for a variety of reasons,
choose to use electric meters that do not transmit radio signals. See Stenman, 311 Mich App at
373-375. RCG cites testimony from DTE’s witnesses in which they indicated that the issues
relating to the imposition of opt-out charges were not considered or decided anew in this case, and
asserts that “[t]he inescapable conclusion is that no adequate cost explanation or evidence has been
provided by DTE to justify the unnecessary initial or monthly opt-out surcharges.” However, as
DTE’s witnesses made plain, DTE was not seeking to introduce newly justified opt-out charges,
but rather was seeking a continuation of policies as decided in earlier proceedings. The PSC
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rejected RCG’s argument because RCG failed to present any evidence or arguments that had not
already been repeatedly presented, ruled on, and affirmed on appeal.
This Court has noted that “ratemaking is a legislative, rather than a judicial, function, and
thus the doctrines of res judicata or collateral estoppel[4] ‘cannot apply in the pure sense.’ ” In re
Application of Consumers Energy Co for Rate Increase, 291 Mich App 106, 122; 804 NW2d 574
(2010), quoting Pennwalt Corp v Pub Serv Comm, 166 Mich App 1, 9; 420 NW2d 156 (1988).
This Court further stated, “Even so, issues fully decided in earlier PSC proceedings need not be
‘completely relitigated’ in later proceedings unless the party wishing to do so establishes by new
evidence or a showing of changed circumstances that the earlier result is unreasonable.” In re
Application of Consumers Energy, 291 Mich App at 122, quoting Pennwalt Corp, 166 Mich App
at 9.
RCG asserts generally that the progress DTE has made in implementing AMI is, standing
alone, grounds for revisitation of the opt-out surcharges established at the onset. However, RCG
does not cite information from the record to show that any new information reveals continued
application of those initial surcharges to be excessive. Further, DTE states in its appellate briefing
that, consistent with an earlier PSC order, it “anticipates filing an application to review the opt-out
charges in a separate docket after AMI installation is complete.” If RCG has suggested that the
PSC might reasonably have called for such comprehensive review before completion of the AMI
installation, it has nonetheless failed to show that awaiting completion was unreasonable. See
MCL 462.26(8). We reject this claim of error.
VIII. CONCLUSION
For the reasons discussed, we vacate the PSC’s order to the extent of the dollar amount of
its disallowance of recovery for DTE’s 4G upgrade of 300 additional relays, and we remand for
the PSC to recalculate the amount of that disallowance and provide a reasonably detailed
explanation of its basis for that amount. In all other respects, we affirm. We do not retain
jurisdiction.
/s/ Michael J. Kelly
/s/ Amy Ronayne Krause
/s/ James Robert Redford
4
“Under the doctrine of res judicata, ‘a final judgment rendered by a court of competent
jurisdiction on the merits is conclusive as to the rights of the parties and their privies, and, as to
them, constitutes an absolute bar to a subsequent action involving the same claim, demand or cause
of action.’ ” Wayne Co v Detroit, 233 Mich App 275, 277; 590 NW2d 619 (1998), quoting Black’s
Law Dictionary (6th ed, 1990), p 1305. “Collateral estoppel bars relitigation of an issue in a new
action arising between the same parties or their privies when the earlier proceeding resulted in a
valid final judgment and the issue in question was actually and necessarily determined in that prior
proceeding.” Leahy v Orion Twp, 269 Mich App 527, 530; 711 NW2d 438 (2006), citing 1
Restatement Judgments, 2d, § 27, p 250.
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