Net Metering in Massachusetts

At Energy Tariff Experts, we've found that Net Metering (NM) and Virtual Net Metering (VNM) are a source of confusion for end use customers and energy professionals. The rules can be confusing and the variety among calculation methodologies for different utilities and rates can be hard to keep track of. In this blog post, we are going to walk through NM for larger customers in the Massachusetts (MA) National Grid service territory.

First, a little background. NM is not new. Its been around since 1978 when the Public Utility Regulatory Policy Act (PURPA) required utilities to allow customers to install self generation equipment and obligated the utility to purchase excess power. Most PURPA projects consisted of cogeneration and many were net metered. Over the last several years, NM has become a big deal due to its importance to the solar industry. The vast majority of new NM has been driven by solar and in some utilities, the tariffs are still trying to catch up with industry developments.

The current solar NM regime in MA has its genesis in the Green Communities Act of 2008. This act mandated that Investor Owned Utilities (IOUs) (e.g., NStar, NGrid, WMECO, and Unitil) credit customers for NM solar output at the retail $/kWh rate instead of the wholesale rate (set by ISO-NE). It created separate credit calculations for private and public sector customers as well as caps on the amount of capacity eligible for NM. These caps filled up pretty quickly and in August 2012, MA Senate Bill 2395 (note the ironic title) was passed which raised the caps to 3% of each IOU's peak load for both public and private sector owned systems. You can view the amount of capacity remaining under each NM cap at the MA System of Assurance website. NM is critical for the economics of many solar installations and the fact that the NM capacity caps will be fully subscribed in 2014 will be an issue. The future of NM in MA has been a back burner issue over the last few months while the details of the SREC II program have been in development.

One item that many have trouble gasping is the difference between NM credits and VNM credits. The graphic below helps to illustrate the difference between the two. VNM credits represent the financial value of each kWh that is pushed back onto the grid and these credits, in dollars, can be transferred to other accounts. 

For an end use customer, the avoided cost of electricity via displacement of electricity from the grid with electricity generated from solar panels is worth more than the value of NM or VNM credits. For the end user who wants to keep it simple, it often makes sense to size a solar array based on the captive load onsite as the value proposition associated with avoided costs via displacement of electricity is more certain (presuming load is constant). The table below illustrates the billing line items for the G-3 and G-1 rates that are part of the NM and VMN credit calculation. Remember, if there is excess generation in a billing cycle, these credits can be applied to future billings or transferred to other accounts. The avoided costs are simply the summation of all kWh charges and represent the $/kWh value of a kWh generated from a solar array that displaced a kWh from the grid.

The tricky thing with NM or VNM credits is that their value changes on a monthly basis. The Basic Service Charge represents the cost of supply and it varies based on conditions in the ISO-NE wholesale power market. Check out this previous post on the variability of default supply rates for various utilities. As a result, there is inherent uncertainty in the future value of NM and VNM credits in the same way that future power costs are uncertain. 

The graphic below shows a MA NGrid G-3 invoice for customers without and with NM. Note that the non-kWh line items are still present. When on-site generation exceeds on-site load, the resulting surplus is credited to the invoice in dollars as shown below.

VNM is where things can really get tricky. The Host customer will designate one or more accounts to receive the financial value of all of the kWhs exported to the grid. In MA, the accounts designated to receive VNM credits are listed on a Schedule Z form. The graphic below illustrates the process.

Schedule Z designation.png

Currently, VNM credits are allocated to the recipient accounts manually each billing cycle. All of the MA IOUs voiced this as a major issue in MA DPU Docket 11-11. Any manual process is likely to have more errors than bills that are generated through an automated billing system. In addition, due to the fact that billing cycle dates for Host and recipient accounts will likely be mismatched, its possible to have a lag of up to two invoices before VMN credits appear on the recipient account's invoice. The graphic below shows where end users can find their VNM credit amount on their bills.

VNM Transfer Process.png

At Energy Tariff Experts, we audit NM and VNM invoices to ensure proper allocation and credits. We also work as an owners agent to evaluate the financial opportunity associated with proposed solar systems. In MA, an opaque secondary market for VNM credits has developed and we have advised several potential purchasers of the marketplace and transaction structures and contract language.

If you are struggling to understand any aspect of NM or VNM in MA or anywhere else, give us a call. We can do small engagements focused on customer education for a few hundred dollars or devise a bespoke Scope of Work to meet your needs.  

A Closer Look at Demand Charges on NGrid-RI's G-32 Rate

At Energy Tariff Experts, (ETE) we've found that demand charges are a source of confusion for many energy professionals and end users. The NGrid-RI (née Narragansett Electric) medium commercial rate, G-32, provides a great example of the nuances that one might encounter when reviewing billed demand charges. The image below is a dissected excerpt from page 2 of the G-32 invoice. The bill date is from early 2013 and although there has been a modest rate change since, the rate structure and bill format have not changed. 

RI G-32 invoice.png

The distribution billings have been divided into the following groups: fixed charges (blue box); volumetric charges billed by kWh (purple box); and demand charges billed in either kW or kVA (red box). Note that the billed demand value is 255.2 kVA which does not match either the kW or kVA measured demand for the billing period. The measured demand for the billing period is shown on the middle right section of the bill, near the callout box that calculates the Power Factor for the Peak period of the billing cycle. In order to determine why the billed value for demand does not match the measured value for demand, one must go to the Tariff to see how the demand charges are calculated. The NGrid-RI rate tariff can be found here (see link on right to open PDF). Below is the relevant excerpt from the tariff that explains how the billed demand is determined.

G-32 determination of demand.png

You'll note that demand is calculated as the greater of four options. End users with a Power Factor less than 90% will be subject to the provisions of item b. In the case of the end user whose bill is shown above, their billed demand was determined in accordance with item c. In July of 2012, this end user had a billed demand of 340 kVA and their Power Factor was well below 90%. Therefore, per the provisions of item b,  the billed demand value of 340 kVA is inclusive of the Power Factor penalty for Power Factors less than 90%. In the bill shown above, you'll note that 255.2 kVA is equal to 75% of 340 kVA.  Due to the provisions of item c, this end user's peaky load, exacerbated by a poor Power Factor during their peak demand month of July 2012, has resulted in an elevated demand charge that has carried forward for multiple billing cycles.

There is another important quirk in the way demand is billed on this rate. The Transmission Demand Charge line item reflects billings for the full 255.2 kVA while the Distribution Demand Charge line item only reflects billings for 55.2 kVA. In essence, demand is billed on a step-wise basis on the G-32 rate. For all billed demand below 200 kW/kVA, only the Transmission Demand Charge applies.  As a result, the marginal cost for each unit of demand below 200 kW/kVA is $2.92 (on this bill, the rate has subsequently increased). Once billed demand crosses the 200 kW/kVA threshold, the marginal cost increases because the Distribution Demand Charge then applies to all incremental demand over 200 kW/kVA. On this bill, the marginal cost of demand over 200 kW/kVA rises to ($3.40 + $2.92 = $6.32) (both rates have subsequently increased).

The step-wise nature of the incremental costs associated with demand charges on the G-32 rate has implications for an energy efficiency strategy. Eliminating demand over 200 kW/kVA and improving Power Factor will return a savings of $6.32 kW/kVA. These savings may be larger if the load is peaky and the provisions of item c in the demand charge calculation apply. Once demand is brought below 200 kW/kVA, the marginal cost of a unit of demand drops by approximately half, and the economics of eliminating demand are not as good. If an end user can accomplish a demand reduction to the 200 kW/kVA level, they will then see a better return on investment by focusing on energy efficiency measures that reduce kWh usage.

If you are trying to devise a high ROI energy efficiency strategy and are trying to gain a better understanding of demand charges, call us. We can probably help you.