What to know about DTE’s net metering replacement in Michigan

NOTE: This was originally posted in 2022. We updated it in June 2024 to reflect the latest information.

For residential solar customers in the US, net metering policies — which traditionally pay the owners of solar PV systems the retail electricity price for the energy their solar installation sends to the grid — have been crucial in making solar a good investment.

Increasingly, however, utilities are changing their net metering policies (also called net energy metering or NEM). These changes often mean reduced savings for solar customers–and potentially a harder sale for solar installers. And unfortunately for solar customers in Michigan, most (if not all) of their utilities no longer offer true net metering.

Michigan’s DTE Energy net metering program was essentially made null back in 2019 — which has had a significant detrimental impact on Michigan solar customers’ savings and payback periods. According to Bridge Michigan news, their new program increased the solar payback period from 9.4 years to 13.3 years on average.

In this blog, we quantify the impacts of DTE’s net metering replacement policy, with a case study of a typical home, as well as an analysis of impacts for customers at different levels of energy usage and solar offset (percentage of the customer’s usage that their solar installation offsets). We conclude with some solar design guidance to help you maximize the value for your solar customers in DTE territory.

See how one solar leader is making solar work for customers in Michigan in this Michigan State Solar case study.

What happened to DTE’s net metering in Michigan?

DTE’s net metering program is no longer in effect. But, there is still an incentive program for solar customers who produce excess energy in Michigan. We’ll explain, but first, a little back story.

Back in 2016, the Michigan legislature passed bills requiring the Michigan Public Service Commission (PSC) to phase out net metering for solar in Michigan and create a new replacement program. 

After rejecting a prior proposal from DTE which would have paid solar customers only the wholesale rate for the solar energy they sent to the grid, the PSC approved DTE’s new proposal on May 2, 2019, which some had called a “middle ground.”

DTE electric was the first utility to propose a solution, which included a Distributed Generation (DC) program tariff, called the “Rider 18 Distributed Generation Program.” The new program took effect on May 9, 2019 for new solar customers; existing solar customers were grandfathered into the original net metering program for 10 years.

 

What replaced DTE’s net metering program?

DTE’s new Distributed Generation Program (Rider #18) replaced its Solar Net Metering rules (Standard Contract Rider #16). The core of the new Distributed Generation program is called an “Inflow–Outflow Mechanism,” which requires a smart meter that measures and sums power flows both to the grid and from the grid.

Now, the inflow-outflow mechanism does still credit solar customers for the extra electricity their panels produce. However, presumed transmission costs will now be subtracted from that energy payout. As the Bridge reported, Rider 18 led to a credit decrease of about 45 percent compared to the DTE net metering program.

In the current implementation, inflow and outflow are measured in netted hour intervals; in the future, they may be instantaneous (or second-long netting) which will generally be worse for the customer.

What are inflow and outflow?

Inflow is defined as the electricity that is delivered to the customer from a utility distribution system.

Outflow is defined as the excess solar energy not used by the customer that is then sent out to the general electric grid.

How can Michigan solar customers access DTE’s Rider 18 program?

Any DTE customer who installs a solar panel system can apply for the Rider 18 Distributed Generation Program. The program has five levels that are tiered based on size of project, with most residential installations falling under Level 1 (systems up to 20 kW in size). Here’s how to gain access to interconnection:

• Step 1: First, the solar project size must be determined, the solar design drawings finalized and other required interconnection information gathered.
• Step 2: Fill out DTE’s interconnection application and pay the appropriate application fee. For projects under 150 kW, it’s a $50 fee, and goes up to $500 for over 1 MW.
• Step 3: Wait for DTE to review your application. You’ll hear back within 10 business days whether or not your project has been approved and which track it will be on or if you need to revisit the application stage.
• Step 4: Once approved, DTE will go through “initial review screens.” Essentially, they will come inspect your project and make sure it’s safe, compatibile, and up to regulation standards. If your project does not pass this stage, DTE will notify you about how to proceed.
• Step 5: If all is good, DTE will extend an interconnection agreement. You’ll need to sign and return this agreement along with the interconnection payment, which is an undefined amount of “the cost of interconnection facilities and distribution upgrades,” according to DTE energy. You’ll have 20 business days to return the interconnection agreement.
• Step 6: Wait for DTE to sign the interconnection agreement, which should happen within 10 business days.
• Step 7: When your project is complete and has passed all necessary inspections, you’ll let DTE officials know so they can verify everything is good to go.

DTE’s NEM replacement: Structurally similar to California’s NEM 2.0

The structure of DTE Energy’s Distributed Generation rider is similar in many respects to California’s NEM 2.0 plan. Let’s look at a breakdown of how these policies compare:

DTE’s rider also stipulates that credits from excess generation can’t be used to pay off accrued generation charges, just like California’s NEM 2.0 rules don’t allow export credits to pay off accrued non-bypassable charges.

Modeling DTE’s DG rate in Aurora

If your company is dealing with DTE net metering changes in solar designs, how do you make sure that you’re accurately predicting your cost/benefit analysis?

Aurora Solar software allows solar contractors to precisely model the finances of solar installations under different utility rates, so we used Aurora’s financial analysis platform to understand the impacts of this rate. Here’s how you can model the finances of your DTE customer’s solar project.

How to model finances of DTE project for a customer?

Because DTE is effectively labeling the distribution component of its rate as a “non-bypassable charge,” users of Aurora’s Utility Bill Savings calculator can model this rate by selecting an export rule of “Fixed Reduction” and setting the reduction to the value. Looking at DTE’s latest ratebook, that value is $0.07024/kWh for the D1 Residential Rate, and approximately $0.06886/kWh for the D1.2 TOU rate.

Cost to the solar customer

Let’s look at how this change can impact an example house near Ann Arbor. Our model house consumes 9,000 kWh per year, the state average, and we fit a 5 kW system that offsets about 55% of the home energy usage, after losing 13% of sunlight to shade. We assigned this customer to Rate D1, which is the standard tiered residential rate for DTE Electric Co.

Under DTE Energy’s old NEM rules (Rider 16), the system would have saved the customer 63% of their annual electric bill, or about $71 per month. The bill-offset percentage is higher than the energy-offset percentage because the system offsets the energy usage of higher-cost tiers first.

When we changed the advanced rules to include an export reduction of $0.07024 per kWh, based on Rider 18 in the latest DTE rule book, we found that the customer’s bill savings fell to only $55 per month, or 49% of their bill offset. The chart also shows that the customer’s bill is above the fixed fee of $7.50 each month; this is due to the customer paying their distribution charges.

Impact of policy changes on customers

Of course, to fully understand the impacts of these policy changes we need to understand how they impact all types of systems, not just this one scenario. In the subsequent section, we share findings on the financial impact of these changes based on our analysis of billing impacts for customers across a range of energy usage levels (6000 kWh to 18000 kWh per year) and a range of energy offset levels (30% to 110% per year), an approach we’ve used in other studies.

Design considerations: Design for the optimal energy offset percentage

Let’s take a look at how to design PV systems to optimize value for your customers under these new net metering rules. While California’s NEM 2.0 provides a handy analogy for understanding how these rules work, the design rules of thumb for Michigan solar designs under this policy are very different than for designs under California’s NEM 2.0.

In California’s NEM 2.0 setup, the small size of the non-bypassable charge (less than 3 cents per kWh, with overall rates above 20 cents per kWh) coupled with the functionality of minimum monthly bills meant that installers could slightly oversize a PV system to maximize a customer’s net present value, even though the customer would be paying a larger post-solar bill compared customers whose solar installations were installed under NEM 1.0.

DTE’s net metering change is much more significant than California’s NEM 2.0. Distribution accounts for nearly half of the rate for a full-service customer on the D1 rate schedule, and represents a majority of the off-peak charges for the D1.2 time-of-day rate. In addition, DTE has a monthly service fee that can’t be offset by solar credits, but also doesn’t act as a mechanism to absorb some of the distribution costs.

As a result, a customer’s Net Present Value is maximized at a much smaller system offset level than the original net metering tariff: around 85% for a D1 customer and around 65% for a Time-of-Day customer. The charts of Net Present Value below also paint a bleak picture of the value of systems — the value falls nearly 50% and in some cases is now worse than investing the money at 3% somewhere else.

As a note, our model assumed that the customer doesn’t use electricity for heating or hot water based on EIA data, but when we ran the analysis with those appliances included in the energy profile, we found that the customer had a lot less self-consumption of solar energy, resulting in higher distribution charges and an overall worse financial outcome. Customers who have a consumption profile that doesn’t align well with solar production will need special consideration when looking at their bill savings.

Conclusions

Revisions to net metering policies can have significant effects on solar customers and DTE’s changes in Michigan are no exception. The impact of this new DTE structure on solar customers is quite severe, because the non-bypassable distribution portion of the rate makes up a large proportion of the overall electric tariff. Solar installers in DTE service territory will need to be careful to not overpromise customers on savings, because unwary residents would find it a shock that a 90% energy offset system will actually only save them 60% of their bill.

Installers and other groups will also want to be wary of upcoming rule-making and new policies that are working their way through state legislatures and public utilities commissions. Unlike California’s NEM 2.0 policy or Nevada’s NMR-405 policy (barring the temporary rescinding of NEM programs), the DTE rate case is not a smooth transition away from standard net metering policy.

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