STATE OF MICHIGAN
BEFORE THE MICHIGAN PUBLIC SERVICE COMMISSION
*****
In the matter, on the Commission’s own motion,
to implement the provisions of Sections 173 and
183(1) of 2016 PA 342, and Section 6a(14)
of 2016 PA 341. 1

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Case No. U-18383

At the April 18, 2018 meeting of the Michigan Public Service Commission in Lansing,
Michigan.

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

ORDER

On December 21, 2016, Governor Rick Snyder signed 2016 PA 341 (Act 341) into law.
Section 6a(14) of Act 341, MCL 460.6a(14) requires the Commission to conduct a study on the
appropriate tariff for customers who participate in the net metering program or the distributed
generation (DG) program within one year of the effective date of the Act. 2 Section 6a(14)
specifically provides:
Within 1 year after the effective date of the amendatory act that added this
subsection, the commission shall conduct a study on an appropriate tariff
reflecting equitable cost of service for utility revenue requirements for customers
who participate in a net metering program or distributed generation program
under the clean and renewable energy and energy waste reduction act, 2008 PA
295, MCL 460.1001 to 460.1211. In any rate case filed after June 1, 2018, the
The case caption has been updated to include the requirements with respect to distributed
generation contained in Act 341.
1

2

Act 341 became effective April 20, 2017.

 commission shall approve such a tariff for inclusion in the rates of all customers
participating in a net metering or distributed generation program under the clean
and renewable energy and energy waste reduction act, 2008 PA 295, MCL
460.1001 to 460.1211. A tariff established under this subsection does not apply to
customers participating in a net metering program under the clean and renewable
energy and energy waste reduction act, 2008 PA 295, MCL 460.1001 to
460.1211, before the date that the commission establishes a tariff under this
subsection, who continues to participate in the program at their current site or
facility.
In response to this mandate, the Commission Staff (Staff) convened a Distributed Generation
Workgroup (DG Workgroup) and held an initial meeting in March 2017. Seven additional
meetings were held over the remainder of 2017, with the workgroup process culminating in a
report and proposed DG tariff as required under Section 6a(14). DG Workgroup participants
included representatives from utilities, environmental policy and advocacy groups, and business
and technical organizations.
The three general tasks for the DG Workgroup included: (1) investigate the grid-balancing
functions of smart inverters as required under Section 173(60)(b) of 2008 PA 295 (Act 295);
(2) develop and implement a DG program within 90 days of the effective date of 2016 PA 342
(Act 342), 3 as required under MCL 460.1173 4; and (3) complete a study to determine an
appropriate DG tariff as required under Section 6a(14), MCL 460.6a(14), by April 20, 2018. The
efforts to develop a DG tariff culminated in a draft report and proposed tariff circulated to
stakeholders for comment on December 15, 2017. A final report (DG Report) and proposed DG
tariff were filed in this docket on February 21, 2018.

3

Act 342 became effective April 20, 2017.

4

The Commission approved an interim DG program in an order issued on July 12, 2017, in
this docket.
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 In the DG Report, the Staff recommended that an Inflow/Outflow billing mechanism be
implemented, 5 under which inflow (i.e., customer energy purchases from the utility) would be
priced at the full retail rate, while power outflows to the grid from the customer’s generation
would be valued, at least initially, at the utility’s avoided cost. According to the DG Report:
The method separates power inflows from power outflows, relying on two distinct
and independent sets of meter data to establish consistent and appropriate cost-ofservice (COS) allocators and billing determinants, rather than netting the two as is
done for net energy metering (NEM).
***
The separation of power inflows from power outflows readily allows for rate
designs that incorporate traditional cost of service study (COSS) methods, thus
ensuring that DG customers are assessed for their fair and equitable use of the
grid. It also provides an independent framework for equitably compensating DG
customers for excess power injected into the grid.
DG Report, pp. 1-2.
The Staff explained that the Inflow/Outflow method is a framework designed to replace both
the true net metering and modified net metering approaches that were authorized under Act 295.
The Staff further explained:
The framework is simple, accommodates a wide array of potential future rate
designs, such as those including demand charges, dynamic pricing, and dynamic
credits. In addition, the Inflow/Outflow billing mechanism is transparent in
effecting clear and accurate price signals, and thus can form the basis for future
load-control and demand-response programs that target DG customers. It also
provides a pricing platform for future implementation of customer-sited advanced
energy-storage technologies, small-scale combined heat and power systems and
potential new emerging technologies.
Id., p. 10.

5

The Staff also evaluated other approaches including net metering, modified net metering
with a grid charge, and a Buy-All, Sell-All billing method.
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 Noting the small number of DG customers currently enrolled in the program, the Staff
suggested that the new cost-based DG program should be implemented through “retail rateschedule riders, as was done for the NEM program, rather than creating new and separate DG
rate schedules.” Id., p. 2.
Ultimately, the Staff made three recommendations for going forward:
(1) In any general rate case filed after June 1, 2018, utilities should be instructed
to file the attached concept tariff-rider, which includes an Inflow/Outflow pricing
mechanism as a foundational framework. The utilities may file additional
proposals if desired. Any existing NEM tariff-riders would be amended to
indicate that the NEM program is closed to new DG customers upon the effective
date of the new tariff.
(2) Upon approval of the Inflow/Outflow concept tariff (on or before April 20,
2018), a new contested proceeding should be established by the Commission to
set a uniform outflow compensation method for all regulated utilities.
(3) If the Commission adopts the Inflow/Outflow concept tariff as recommended
by Staff, all rate regulated utilities should be ordered to file a report, within 60
days, describing their ability to meter and bill according to the Inflow/Outflow
mechanism, and incorporate time-based rates for both power inflows and power
outflows. Utilities should provide an estimate of the cost to modify billing
infrastructure, if necessary, to accommodate the new tariff.
Id., p. 30.
On February 22, 2018, the Commission issued an order (February 22 order) finding that the
Staff’s proposed Inflow/Outflow billing method, developed from the completed study, comports
with the requirements of Act 341. The Commission also asked for comments from stakeholders
on the following:
(1) Are there any concerns with the recommended process for developing and
approving a DG tariff as discussed above (i.e., an interim case to develop a
uniform outflow compensation method, coupled with a rate case to finalize the
DG tariff)?
(2) The DG Study relied primarily on the language in MCL 460.6a(14) to develop a
method and tariff “reflecting equitable cost of service for utility revenue
requirements” for DG customers. This method would replace net metering and
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 modified net metering for customers who enroll after the tariff is approved. Are
there any legal limitations to the implementation of the Inflow/Outflow method
and tariff as proposed in the DG Report? Specifically, does adoption of the
Inflow/Outflow billing method conflict with Sections 177(4) and (5) of 2008 PA
295, MCL 460.1177(5)?
(3) Do any providers anticipate any technical limitations with respect to measuring
and billing/crediting under the Inflow/Outflow method?
(4) In the July 12 order, the Commission found that the current net metering program
should continue as the DG program until new DG tariffs are approved in rate
cases filed after June 1, 2018. In addition, under MCL 460.1183 and MCL
460.6a(14), any customer “participating” in a net metering or DG program before
the new DG tariff is approved may continue net metering for 10 years, or may opt
to receive service under a DG tariff. At what point should a customer be
considered to be “participating” in a net metering program?
Comments were due by March 12, 2018, and reply comments were due by March 26, 2018.
The Commission received a significant number of comments from customers expressing support
for the current NEM structure and explaining the associated environmental and economic
benefits NEM provides. Stakeholder organizations, solar companies, the utilities, and members
of the Legislature also submitted comments. Below is a summary of some of the pertinent
comments received.
In response to the Commission’s request for comments on the process to develop the DG
tariff, Sunrun, Inc. (Sunrun) argued that Act 342 prescribed that the Commission should develop
a tariff prior to including such a tariff in a rate case filed after June 1, 2018. First, Sunrun asked
the Commission to clarify that it is establishing only a DG tariff, rather than a new DG
“program,” which would require a rulemaking procedure under the Administrative Procedures
Act of 1969, MCL 24.201 et seq. (APA). Sunrun also stated that the proper procedure is for the
Commission to determine the final tariff in one contested proceeding, rather than multiple rate
cases, to avoid duplicative proceedings. Douglas Jester of 5 Lakes Energy agreed with Sunrun’s
position, but argued that the scope of the contested proceeding should not be limited to
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 determining outflow. Instead, the proceeding should encompass determination of the entire DG
tariff. 5 Lakes Energy’s comments, p. 3. The Michigan Energy Innovation Business Council
(EIBC) agreed with Mr. Jester, arguing that “inflow and outflow values must be determined
following COS principles in the contested case proceeding” because “full class retail rates do not
necessarily reflect the COS for DG customers.” EIBC’s comments, p. 4.
DTE Electric Company (DTE Electric), Consumers Energy Company (Consumers), and the
Michigan Electric and Gas Association (MEGA) took issue with the Staff’s proposed stand-alone
contested proceeding to determine the outflow component of the Inflow/Outflow billing
mechanism. DTE Electric and Consumers argued that allowing the utilities to file their own
proposed DG tariff in a post-June 1, 2018 rate case, while also holding a separate contested case
to determine outflow would prejudge the DG tariff, in violation of due process and the APA.
DTE Electric’s comments, pp. 4-7; Consumers’ comments, pp. 3-4. DTE Electric further
contended that the statute directs the Commission to approve any DG tariff in a rate case, not a
separate contested proceeding, and that compelling the utility to file the Staff’s tariff violates
Union Carbide Corp. v Public Service Commission, 431 Mich 135; 428 NW 2d 322 (1988), by
“usurp[ing] a utility’s right to propose rates and tariffs of its own choosing and otherwise
manage the utility’s business.” DTE Electric’s comments, p. 8. Instead, DTE Electric
contended, it will consider the Staff’s report and recommendation, and file its own DG tariff in
its next post-June 1, 2018 rate case. MEGA argued that smaller utilities file rate cases less
frequently than the larger utilities and thus, proposed that the Commission allow the smaller
utilities to file a DG proposal in a stand-alone docket independent of a rate case. MEGA’s
comments, pp. 2-3.

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 The Commission also received comments regarding the interim DG tariff. In the DG Report,
the Staff suggested a second interim outflow rate set at the DG customer’s power supply
component of the retail rate in the event that a utility’s rate case concludes before the stand-alone
contested proceeding. DG Report, p. 17. Sam Singh, Michigan House of Representatives
Democratic Leader; EIBC; and Chart House Energy disagreed with the Staff’s recommendation.
Representative Singh, EIBC, and Chart House Energy proposed that the Commission continue
the status quo net metering until a final DG tariff is established.
As to the inquiry into any possible legal limitations, specifically Section 177(4) and (5) of
Act 295, MCL 460. 1177(4) and (5), DTE Electric, Consumers, and MEGA commented, arguing
that Section 177 already establishes the appropriate credit for a DG customer’s outflow. DTE
Electric contends that Section 177 limits credits to the total power supply charges on the
customer’s bill, excluding transmission costs, and that under the Staff’s Inflow/Outflow
mechanism, credits could offset transmission and distribution cost in violation of Section 177.
DTE Electric also argued that the use of avoided cost to credit a DG customer’s outflow, does
not comply with the two compensation methods, locational marginal pricing (LMP) or the power
supply component, dictated in Section 177(4). DTE Electric’s comments, pp. 9-10.
Sunrun also raised an issue with the Staff’s study in response to the Commission’s request
for comments, arguing that the Staff did not complete a full COSS to reflect “cost of service”
under its “statutory meaning.” Sunrun’s comments, p. 8. Thus, according to Sunrun, the Staff’s
report does not establish whether NEM or Inflow/Outflow reflect an equitable COS. Id., pp. 7-8.
Michigan Senator Mike Shirkey, EIBC and Chart House Energy agreed with Sunrun arguing that
the Staff had not completed a full COSS in violation of Section 6a(14). Chart House Energy
suggested that, based on the Staff’s partial COSS, the Commission implement a first year DG
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 tariff of $0.02/kWh credit for all power generated by a DG customer and that all excess power
should be credited under true net metering. Chart House Energy’s comments, p. 6. EIBC took
issue with the Staff’s recommendation to keep DG customers in their underlying rate class.
EIBC asserted that DG customers’ load profiles are so different from non-DG customers that it is
appropriate to separate DG customers into their own sub-class. EIBC’s comments, p. 4.
As to any technical limitations to implementing the Inflow/Outflow billing method, Sunrun
expressed concern that some utilities such as Alpena Power Company, Indiana Michigan Power
Company, Northern States Power Company-Wisconsin, Upper Peninsula Power Company, and
Upper Michigan Energy Resources Corporation do not have advanced metering infrastructure
(AMI) meters deployed, and would thus, be unable to implement the Inflow/Outflow billing
mechanism that depends upon AMI bidirectional metering. MEGA made the argument that,
given the low participation in net metering, electric providers should be allowed maximum
flexibility to implement the change to DG.
Regarding how the Commission should define “participating” when determining the cutoff
point for interim DG customers to be transitioned to the new DG tariff, Sunrun and DTE Electric
did not oppose the Staff’s proposal to define “participating” as having a completed DG
application pending before the utility. DTE Electric agreed, “as long as the customer has cured
any defects of a deficient application prior to the effective date of the Commission Order.” DTE
Electric’s comments, p. 14. The company also requested that the Commission require a
customer with a completed application to have installation completed and approved within six
months. Id. Consumers disagreed with the Staff’s proposal and asserted that, “[i]n order to fully
participate in the interim DG Program, the completed application needs to be accompanied by a
signed Parallel Operating Agreement for an Installed and Functioning system (i.e., confirmed
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 contractual arrangement for the installation of a qualifying net metering system).” Consumers’
comments, pp. 11-12. MEGA agreed with Consumers that participation should mean
enrollment, installation of a DG system, and actual billing. MEGA’s comments p. 5.
Discussion
The Commission is grateful for the Staff’s and stakeholders’ participation in the process to
implement the new DG laws, and appreciates the comments received in this matter. The
feedback from customers, stakeholders, and the utilities has been immensely helpful to the
Commission in the decision-making process. The Commission has carefully reviewed and
considered the materials presented in the DG Workgroup, the DG Report, and the comments
received in this docket. The Commission now addresses the following issues in turn.
a.

Legal Limitations of the Inflow/Outflow Tariff and Study
i.

Study to Develop a Tariff Reflecting Cost of Service

The Commission takes this opportunity to clarify, in response to Sunrun’s comments, that it
is indeed developing a tariff, and that the remainder of the DG program will remain intact, as the
Staff explained in the DG Report. The Commission agrees with the Staff’s interpretation of
“tariff” to mean a billing mechanism. Section 6a(14) uses the terms “tariff” and “rate” distinctly,
which implies that “tariff” is not a monetary amount that the Commission must assign, but rather
a structure or mechanism that the Commission must develop to implement Section 6a(14). The
Commission also looked to the definitions of “true net metering” and “modified net metering”
under Act 342, which are defined as “billing mechanisms.” It follows that a DG tariff to replace
true and modified net metering would carry the same definition of billing mechanism. As such,
the Commission finds it has clear authority to develop a DG tariff reflecting COS.

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 DTE Electric and Consumers raised arguments that the Commission cannot compel the rateregulated utilities to file the Inflow/Outflow DG tariff in a post-June 1, 2018 rate case, as
recommended by the Staff. The Commission disagrees. “As a creature of the Legislature, the
commission possesses only that authority bestowed upon it by statute.” Union Carbide Corp.,
431 Mich at 146. The statute in this case, Section 6a(14), clearly confers upon the Commission
the authority to develop a DG tariff and explicitly directs the Commission to “approve such a
tariff” in a rate case filed after June 1, 2018. In order to fulfill that obligation and to approve a
DG tariff in a rate case, the Commission must have the Inflow/Outflow tariff filed to evaluate its
application to the particular circumstances of the filing utility.
Regarding the study conducted to develop the DG tariff, Sunrun asserted that the
Commission has not fulfilled its statutory obligation because it has not completed a full COSS.
The Commission finds that it has complied with the Legislature’s directive to conduct a study on
an appropriate tariff reflecting equitable COS within one year from the effective date of Act 341.
The Staff facilitated the extensive DG Workgroup, engaged with stakeholders, and drafted a
comprehensive report on this issue.
In examining the cost to serve NEM customers, the Staff “undertook a cost-of-service
analysis to compare the residential customer class as a whole to residential NEM customers as a
distinct customer class, using 2014 numbers provided by DTE Electric Company.” DG Report,
p. 18. While Sunrun asserted that reliance on the 2014 NEM data was insufficient, the
Commission disagrees. The amount of NEM data available is limited, and the Staff conducted a
thorough study and analysis with the information available. In the DG Report, the Staff
acknowledged this limitation and explained that as Inflow/Outflow is implemented, more
information will become available.
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 It is acknowledged that in future years, cost-of-service studies underlying general
rate cases may be designed to allocate costs to specifically identified DG classes
with corresponding unique rate schedules (or subclasses, with corresponding
retail-rate adjusters). The long-term procurement of detailed register and interval
data from the AMI system will facilitate both numerical analysis and decisionmaking supporting the cost allocation and rate design at such future time. This
will enable the fine-tuning of rates, if needed.
Id., p. 12.
The cost and benefit impacts associated with DG customers are not static, but can vary based
on a multitude of factors including location, utility infrastructure conditions, weather, and the
number of DG customers on the grid, among other factors. As the Staff explained in the DG
Report, the Inflow/Outflow tariff is an adaptable framework that will allow the Commission to
collect the data and information necessary to accurately capture the costs and benefits
attributable to DG customers in a way that could not be done under traditional net metering. As
explained above, the statute directed the Commission to develop a tariff, which is distinct from a
rate, or specific numerical value. The Staff fulfilled that directive by developing the
Inflow/Outflow tariff, which is a billing mechanism that can be adapted over time to ensure
conformance with COS principles even as conditions change.
The Inflow/Outflow tariff assigns a rate to the DG customer’s total inflow and total outflow
which is then measured via AMI meters. These simultaneous measurements create a complete
picture of the customer’s energy usage and excess generation, unlike traditional net metering that
only captures the customer’s net usage. This improved data collection will allow the
Commission to continuously evaluate DG program costs and benefits and provide accurate price
signals to DG customers.
The Commission finds that the Staff developed a tariff reflecting COS for DG customers
based on extensive analysis and the available data, proposed the full retail rate be assigned to
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 customer inflow, and recommended avoided cost as a viable option for the outflow credit. While
the Staff also recommended a separate contested proceeding to further quantify an outflow credit
due to the controversy surrounding this issue, the Commission does not find that such a
recommendation renders the study incomplete. The statute directed the Commission to develop
a tariff, not a specific assigned rate, and the Commission finds that the Inflow/Outflow tariff
resulting from the study satisfies the requirements of Section 6a(14). Therefore, the Commission
finds it has fulfilled the directive under Section 6a(14) to conduct a study to develop DG tariff
reflecting COS.
Further, the Staff recommended that DG customers remain in the assigned underlying rate
class rather than be separated into their own sub-class. 6
Staff strongly believes that separating existing COS rate classes into customer
sub-groups is a slippery slope that should be carefully considered so as not to
harm the greater public interest. Separating customers having significant
commonality into unique COS subclasses begs the question of when to stop the
subdivision process. For example, even within the DG subgroup, there can be
large differences in load profiles that are a function of the level of generation
capacity vis-à-vis total annual load.
***
As noted earlier, DG is only one of many items that cause diversity within a class.
Currently in a COSS study [sic], there are no separate classes for DG customers.
Given that there are relatively few DG customers, COSS theory would not
support splitting those customers into a separate class.

6

The DG program authorized by Part 5 of Act 342 includes residential, commercial and
industrial customers that meet eligibility requirements set by the statute. The Inflow/Outflow
tariff for such eligible residential, commercial or industrial customers would be in the form of a
rider attached to the underlying COS rate class for the customer.
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 Id., pp. 24-25. The Commission agrees that there is insufficient diversity at this time between
DG customers and non-DG customers to warrant separating DG customers into their own
separate rate class.
ii.

Section 177(4) and (5) Conflict

In their comments, DTE Electric and Consumers averred that the Staff’s Inflow/Outflow
billing mechanism conflicts with Section 177(4) and (5). The utilities argue that subsection
(4) prescribes the compensation for all excess generation, whether defined on a total outflow
basis or on a net excess basis (outflow minus inflow), and that such compensation is limited to
one of two options, LMP or the power supply component of the full retail rate. The Commission
disagrees with this interpretation.
The correct interpretation of Section 177, which reflects the definition of modified-netmetering billing method under MCL 460.1007(i), is that it establishes a netting system that
divides excess generation into two baskets. Power outflows up to the level of inflow during the
current billing period (or pricing period) are offset on a net energy basis, which is identical to
true net metering. Because netting occurs on an energy basis, there is no need to designate a
compensation rate for this portion of excess generation, and the statute reflects this fact by
leaving the compensation rate undefined. It is, however, effectively equal to the full retail rate
(power supply and distribution charges) during each relevant pricing period.
On the other hand, the remaining portion of excess generation (power outflow exceeding
inflow) is monetized using the prescribed credit formulas set by subsection (4), the LMP or the
power supply component of the retail rate, excluding transmission charges. Pursuant to Section
177, this compensation is not used in the current billing period, but is carried forward to the

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 following billing period as a dollar credit or kilowatt hour (kWh) credit against power supply
charges.
The second issue raised by DTE Electric and Consumers relates to the limitation of
accumulated credits against future bills. In comments, DTE Electric and Consumers made the
argument that any DG credit cannot be used to reduce distribution or transmission charges. This
is an incorrect interpretation of Section 177(4). The relevant subsection (4) provision states,
“[n]otwithstanding any law or regulation, distributed generation customers shall not receive
credits for electric utility transmission or distribution charges.” This exclusion refers to the
formula for calculating compensation, which is expressed in the dual credit pricing options (LMP
or power supply component excluding transmission charges), that immediately follows the
prohibition. Under any reasonable interpretation, the transmission and distribution exclusion
cannot refer to the level of accrued credits that can be applied to the customer bill for the
following billing period since subsection (4) expressly allows the offset of the total power supply
charges (which include transmission charges). Clearly, the transmission and distribution
exclusion only applies to the modified net metering formula for calculating credits for the portion
of outflow that exceeds inflow.
Further, if the credit limitation applied across the board, i.e., to total outflow, then both true
net metering and modified net metering would be prohibited by subsection (4) since both billing
methods credit power inflows at the full retail rate (which includes transmission and distribution
charges). The utilities’ interpretation of Section 177(4) sets the statute in conflict with itself and
is thus erroneous.
Third, DTE Electric and Consumers argue that subsection (5) restricts the Commission from
approving outflow credits from offsetting any distribution charges applied to inflow since those
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 charges are intended to recover the COS pursuant to Act 341. Again, this prohibition is
explicitly directed toward credits for the portion of outflow that exceeds inflow under the
modified net metering billing method.
Section 177 applies only to modified net metering that continues to exist under the
grandfathering provision in Act 342, Section 183 or under the new DG program (with an added
charge to recover the COS). Section 177 does not apply to any DG billing method, such as the
Inflow/Outflow billing mechanism, that implements a COS based tariff under Act 341, Section
6a(14). Instead, under Inflow/Outflow, a rate (full retail) is assigned to the energy supplied to
the customer (the inflow), and a rate is assigned to the energy supplied to the grid by the
customer (the outflow).
b. Procedure Going Forward to Implement the New Distributed Generation Tariff
As the Commission stated in its February 22 order, the Inflow/Outflow billing mechanism
comports with the requirements to establish a tariff that reflects COS, and to assess DG
customers for their fair and equitable use of the grid under Section 6a(14). While the
Commission finds that the Inflow/Outflow billing mechanism meets statutory requirements, the
final determination of a new DG tariff shall be made in a utility’s rate case filed after June 1,
2018. Section 6a(14) states that, “[i]n any rate case filed after June 1, 2018, the commission
shall approve such a tariff for inclusion in the rates of all customers participating in a net
metering or distributed generation program.” The Commission finds that the most efficient
procedure is to approve a new tariff in each utility’s post-June 1, 2018 rate case, which will
allow the Commission to consider the unique circumstance of each utility and other applicable
factors to determine the final DG tariff to include in each utility’s rates.

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 Therefore, in any rate case filed after June 1, 2018, the utility shall file the Inflow/Outflow
tariff, as discussed supra. However, because the Commission is reserving final determination of
a DG tariff for a post-June 1, 2018 rate case, the utility may also file its own alternative DG
tariff. The Commission recognizes the novelty and difficulty in developing a new DG tariff and
finds that permitting the rate-regulated utilities to also file an alternative DG tariff will enable the
most thorough evaluation possible. The Commission also declines to adopt MEGA’s
recommendation to allow smaller utilities to file a DG tariff independent of a rate case, as that
would contradict the statute’s directive.
c. Interim Distributed Generation Program
In the Commission’s July 12, 2017 order, the Commission determined that the current net
metering program should continue as the interim DG program until the new DG program tariffs
are approved in rate cases filed after June 1, 2018. The order also clarified that customers who
enter the DG program prior to the new DG tariff effective date may continue to net meter for 10
years from the date of their enrollment. In the DG Report, the Staff recommended a second
interim DG tariff in the event that the proposed stand-alone contested proceeding to determine
outflow compensation had not concluded in time to be applied to a post-June 1, 2018 rate case.
Under those circumstances, the Staff suggested that outflow compensation be set at the DG
customer’s power supply component of the retail rate.
The Commission declines to adopt the Staff’s recommendation as the Commission is not
ordering a separate contested proceeding to determine outflow compensation. Therefore, until a
final DG tariff is approved in a rate case filed after June 1, 2018, the current net metering
program will continue as the interim DG program.

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 The Commission agrees with the Staff’s recommendation in the DG Report that, under the
interim DG program, a customer will be considered “participating” in the program if the
customer has a completed application pending before the utility prior to the effective date of the
new DG tariff approved in a rate case filed after June 1, 2018. For DG applications submitted
prior to the effective date of the new DG tariff, the utility shall notify the applicant within 10
working days from the date the application is submitted whether the application is complete or
deficient. If complete, the application shall be processed, and the customer will be considered
enrolled in the utility’s DG program. If the application is deemed deficient, the applicant shall
be given 60 days from the date of notification by the utility to cure the deficiency. If the
applicant fails to cure the deficiency, the application will be considered void. The Commission
also adopts DTE Electric’s recommendation and requires that any DG applicant must have a
completed and approved DG installation within six months from the date the DG applicant’s
application is deemed complete.
Conclusion
Section 6a(14) of Act 341 directs the Commission to “conduct a study on an appropriate
tariff reflecting equitable cost of service” and “approve such a tariff” in a rate case filed after
June 1, 2018. Within the timeframe permitted by the statute, the Staff has conducted an
extensive study and analysis, which resulted in the development of the Inflow/Outflow tariff.
The Inflow/Outflow tariff is an adaptable billing mechanism that allows for equitable COS and is
enabled by improved data collection. As the DG program evolves and more data becomes
available, the Commission will better be able to assess the cost and benefit impacts and conduct
rate design consistent with COS principles. While the Commission finds that the Inflow/Outflow
tariff resulting from the study satisfies the requirements of Section 6a(14), the Commission
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 reserves final determination of the DG tariff and accompanying rates for any rate case filed after
June 1, 2018, as the statute dictates. Because the Commission was directed by statute to develop
a DG tariff, the Commission requires the rate-regulated utilities to file the Inflow/Outflow tariff
in their next post-June 1, 2018 rate case. As previously noted, the Commission will also permit a
rate-regulated utility to file an alternative DG tariff if desired, to enable a thorough evaluation of
all viable DG tariff options.
THERFORE, IT IS ORDERED that, in any rate case filed after June 1, 2018, the rateregulated utility must file the Inflow/Outflow tariff, attached to this order as Exhibit A. The rateregulated utility may also file its own distributed generation tariff, if desired.

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

________________________________________
Sally A. Talberg, Chairman

________________________________________
Norman J. Saari, Commissioner

________________________________________
Rachael A. Eubanks, Commissioner
By its action of April 18, 2018.

________________________________
Kavita Kale, Executive Secretary

Page 19
U-18383

 EXHIBIT A

Distributed Generation Tariff

The combination of the customer?s retail rate schedule and this rider (Rider) constitutes the
cost-based distributed generation (DG) tariff pursuant to Public Act 341 of 2016 Section (6)
(14). The customer is billed according to their retail rate schedule for all In?ow and
receives a credit in dollars, rather than kWh, based on the Out?ow Credit provision shown on

the Rider.

The credit for out?ow during the billing month is applied to the total bill less the
customer charge. The customer will always pay the customer charge. Any
unused out?ow bill credit is added to any unused bill credit from previous months and carried
forward to the next month. The utility will not issue a check for unused bill credit unless the
customer leaves the DG program.

C11. DISTRIBUTED GENERATION PROGRAM

A.

The Distributed Generation Program is offered as authorized by 2008 PA 295,
as amended, 1939 PA 3, as amended by 2016 PA 341, Section (6) (14), and
the Commission in Case No. U-

Distributed Generation Definitions

(1) A Category 1 distributed generation customer has one or more Eligible

(2)

(3)

(4)

Electric Generators with an aggregate nameplate capacity of 20 kWac or less
that use equipment certi?ed by a nationally recognized testing laboratory to
1547.1 testing standards and is in compliance with UL 1741 scope 1.1A
located on the customer's premises and metered at a single point of contact.

A Category 2 distributed generation customer has one or more E1igible
Electric Generators with an aggregate nameplate capacity greater than 20
kWac but not more than 150 kWac located on the customer's premises and
metered at a single point of contact.

A Category 3 distributed generation customer has one or more methane
digesters with an aggregate nameplate capacity greater than 150 kWac but not
more than 550 kWac located on the customer's premises and metered at a
single point of contact.

Eligible Electric Generator a renewable energy system or a methane 
digester with a generation capacity limited to no more than 100% of the
customer's electricity consumption for the previous 12 months and does not

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exceed the following:

a. For a renewable energy system, 150 kWac of aggregate generation at a
single site

b. For a methane digester, 550 kWac of aggregate generation at a single site

(5) In?ow the metered in?ow delivered by the Company to the customer during
the billing month or time-based pricing period.

(6) Out?ow the metered quantity of the customer? 5 generation not used on site and
exported to the utility during the billing month or time?based pricing period.

(7) Renewable Energy Resource a resource that naturally replenishes over a
human, not a geological, timeframe and that is ultimately derived from solar
power, water power or wind power. Renewable energy resource does not
include petroleum, nuclear, natural gas, or coal. A renewable energy resource
comes from the sun or from thermal inertia of the earth and minimizes the output
of toxic material in the conversion of the energy and includes, but is not limited
to, all of the following:

Biomass
(ii) Solar and solar thermal energy
Wind energy
(iv) Kinetic energy of moving water, including the following:
waves, tides or currents
water released through a dam
Geothermal energy
(vi) Thermal energy produced from a geothermal heat pump
(vii) Any of the following cleaner energy resources:
(3) Municipal solid waste, including the bio genie and anthropogenic
factions
Land?ll gas produced by municipal solid waste
(0) Fuel that has been manufactured in whole or signi?cant part from
waste, including, but not limited to, municipal solid waste. Fuel
that meets the requirements of this subparagraph includes, but is
not limited to, material that is listed under 40 CFR 241.3(b) or
241.4(a) or for which a nonwaste determination is made by the
United States Environmental Protection Agency pursuant to 40
CFR Pet coke, hazardous waste, coal waste, or scrap
tires are not fuel that meets the requirements of this subparagraph.

C. Distributed Generation Program Availability

The Distributed Generation Program is available for eligible Distributed

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Generation customers beginning with the ?rst day of the 2019 Bill
Month.

A customer participating in a net metering program approved by the
Commission before (date offhe rate case order approving this tariff) shall
have the option to take service under this tariff at the time service under the
terms and conditions of the previous net metering program terminates in
accordance with MCL 463.01 83(1).

The Distributed Generation Program is voluntary and available on a ?rst come,
?rst served basis for new customer participants or existing customer
participants increasing their aggregate generation. The combined legacy net
metering and DG program size is equal to 1.0% of the Company's average in-
state peak load for Full-Service customers during the previous 5 calendar years.
Within the Program capacity, 0.5% is reserved for Category 1 Distributed
Generation customers, 0.25% is reserved for Category 2 Distributed Generation
customers and 0.25% is reserved for Category 3 Distributed Generation
customers. The Company shall notify the Commission upon the Program
reaching capacity in any Category.

Customer Eligibility

In order to be eligible to participate in the Distributed Generation Program,
customers must generate a portion or all of their own retail electricity
requirements with an Eligible Electric Generator which utilizes a Renewable
Energy Resource, as de?ned in Rule Cl 1 .B, Distributed Generation
De?nitions.

A customer's eligibility to participate in the Distributed Generation Program is
conditioned on the full satisfaction of any payment term or condition imposed
on the customer by pre~existing contracts or tariffs with the Company,
including those imposed by participation in the Distributed Generation
Program, or those required by the interconnection of the customer?s Eligible
Electric Generator to the Company's distribution system.

Customer Billing on In?ow Category 1, 2 and 3 Customers

(1) Full Service Customers

The customer will be billed according to their retail rate schedule,
plus surcharges, and Power Supply Cost Recovery (PSCR) Factor on
metered In?ow for the billing period or time?based pricing period.

(2) Retail Open Access Customers

The customer will be billed as stated on the customer's Retail Open
Access Rate Schedule on metered In?ow for the billing period or time-

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F.

G.

H.

based pricing period.

Customer Billing Out?ow Credit

The customer will be credited on Out?ow for the billing period or time?based
pricing period. The credit shall be applied to the current billing month and shall
be used to offset total utility charges (exclusive of the customer
charge) on that bill. Any excess credit not used will be carried forward to
subsequent billing periods. Unused Out?ow Credit from previous months will
be applied to the current billing month, if applicable. Out?ow Credit is non?
transferrable.

(1) Full Service Customers

The Out?ow compensation methodology will be established by the
Commission in a contested case proceeding.

(2) Retail Open Access Customers

The Out?ow Credit will be determined by the Retail Service Supplier.

Application for Service

In order to participate in the Distributed Generation Program, a customer
shall submit completed Interconnection and Distributed Generation Program
Applications, including th 6 application fee of $50 to the Company.

The Distributed Generation Program application fee is waived if the
customer is transitioning from the Net Metering Program.

If a customer does not act or correspond on an application for over 6 months,
when some action is required by the customer, the application may voided by
the Company.

Generator Requirements

The Eligible Electric Generator(s) must be located on the customer's premises,
serving only the customer's premises and must be intended primarily to offset
a portion or all of the customer?s requirement for electricity.

The customer's requirement for electricity shall be determined by one of the

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following methods:

(1) The customer's annual energy usage, measured in kWh, during the previous
12-month period

(2) In instances where complete and correct data is not available or where
the customer is making changes on?site that will affect total usage, the
Company and the customer shall mutually agree on a method to
determine the customer's annual electric requirement

The aggregate capacity of Eligible Electric Generators shall be determined by the
aggregate projected annual output of the generator(s).

The customer is required to provide the Company with a capacity rating in

kW of the generating unit and a projected and annual Kilowatt?hour

output of the generating unit when completing the Company's Distributed I
Generation Program Application. i

The customer need not be the owner or operator of the eligible generation I
equipment, but is ultimately responsible for ensuring compliance with all I
technical, engineering and operational requirements suitable for the

Company's distribution system.

Generator Interconnection Requirements

The requirements for interconnecting a generator with the Company's

facilities are contained in Rule B8., Electric Interconnection and Distributed

Generation Standards, the Michigan Electric Utility Generator Interconnection

Requirements and the Company's Generator Interconnection Supplement to 
Michigan Electric Utility Generator Interconnection Requirements. All such 
interconnection requirements must be met prior to the effective date of a 
customer's participation in the Distributed Generation Program. The customer I
must sign an Interconnection and Operating Agreement with the Company

and ful?ll all requirements as speci?ed in the Agreement. The customer shall

pay actual interconnection costs associated with participating in the

Distributed Generation Program, subject to limits established by the Michigan

Public Service Commission.

Metering Requirements 

Metering requirements shall be specified by the Company, as detailed below.
All metering must be capable of recording in?ow and out?ow and all
parameters metered on the customer's otherwise applicable retail rate
schedule, for both Full Service and Retail Open Access customers.

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K. Distribution Line Extension and/or Extraordinary Facilities

The Company reserves the right to make special contractual arrangements
with Distributed Generation Program customers whose utility service
requires investment in electric facilities, as authorized by the Company's
Rule C1.4, Extraordinary Facility Requirements and Charges, Rule Cl .6,
General Provisions of Service, and Rule C6., Distribution Systems, Line
Extensions and Service Connections, as set out in the Company's Electric
Rate Book. The Company further reserves the right to condition a
customer's participation in the Distributed Generation Program on a
satisfactory completion of any such contractual requirements.

L. Customer Termination from the Distributed Generation Program

A participating customer may terminate participation in the Company's
Distributed Generation Program at any time for any reason on sixty days'
notice. In the event that a customer who terminates participation in the
Distributed Generation Program Wishes to re-enroll, that customer must
reapply as a new program participant, subject to program size limitations,
application queue and application fees.

The Company may terminate a customer from the Distributed Generation
Program if the customer fails to maintain the eligibility requirements, fails
to comply with the terms of the operating agreement, or if the customer's
facilities are determined not to be in compliance with technical,
engineering, or operational requirements suitable for the Company's
distribution system. The Company will provide sixty days' notice to the
customer prior to termination from the Distributed Generation Program,
except in situations the Company deems dangerous or hazardous. Such
notice will include the reason(s) for termination.

Upon customer termination from the Distributed Generation Program, any
existing credit on the customer?s account will either be applied to the
customer's ?nal bill or refunded to the customer. The Company will refund to
the customer any remaining credit in excess of the final bill amount.
Distributed Generation Program credit is non?transferrable.

M. Company Termination of the Distributed Generation Program

Company termination of the Distributed Generation Program may occur upon
receipt of Commission approval.

Upon Company termination of the Distributed Generation Program, any
existing credit on the customer?s account will either be applied to the
customer's ?nal bill or refunded to the customer. The Company will refund to
the customer any remaining credit in excess of the final bill amount.
Distributed Generation Program credit is non-transferrable.

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N. Distributed Generation Program Status and Evaluation Reports

0.

The Company will submit an annual status report to the Commission Staff by
March 31 of each year including Distributed Generation Program data for the
previous 12 months, ending December 31. The Company's status report shall
maintain customer con?dentiality.

Renewable Energy Credits
Renewable Energy Credits (RECS) are owned by the customer.

The Company may purchase Renewable Energy Credits from participating
Distributed Generation Program customers who are willing to sell RECs
generated if the customer has a generator meter in place to accurately measure and
verify generator output. REC certi?cation costs are the responsibility of the
customer.

The Company will enter into a separate agreement with the customer for the
purchase of any RECs.

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