Thinking About An EE Project? Look at Your Bills First

Despite many years in the energy industry, this author is continually stunned by the number of end users and energy professionals who do not understand their utility rate structures or their implications for savings potential. Unfortunately, the status quo is for an energy services firm to identify energy waste, install a solution, and then incorrectly calculate "savings" based on weighted average unit costs, in $/kWh. The reality is that weighted average unit costs can greatly over or understate the true savings opportunity. 

In eastern Massachusetts, the two main Investor Owned Utilities (IOUs) provide a stark contrast in rate structures for large commercial customers that have major implications for how an end user should invest in efficiency. NStar's B7 rate is the most common rate for large commercial customers in the legacy Boston Edison service territory. It charges end users primarily based on peak demand, with particularly punishing demand charges during the summer months. National Grid's G3 rate is the most common large commercial rate in its service territory. The G3 rate primarily charges consumers based on usage volumes in kWh. These differences are clearly evident by reviewing the invoice formats, excerpts of which are shown below.

B7-G3 bill excerpts.png
B7-G3 Rate Table.png

The NStar invoice on the left clearly shows the demand charges which we've highlighted by putting a red box around them. The purple boxes show the demand subtotal and the total distribution charges. If you look closely, you'll see that over three fourths of this invoice consists of demand charges. Now look at the NGrid invoice to the right and you'll see that there is just one demand charge line item. It comprises a much smaller percentage of the total distribution bill and the usage charges, billed in $/kWh, are much higher than those on the NStar bill. The blue table to the above right clearly illustrates the differences in demand charges between the two utility rates. As you can see there is nearly an order of magnitude difference between demand charges that would apply during the summer months. 

In addition to the disparities in what demand costs, there are also differences in when demand is measured. Most utilities have "Peak" and "Off-peak" periods and billed demand is typically the maximum demand that occurs during the "Peak" period. If the maximum demand for a customer occurs during the "Off-peak" period, it is typically discounted so as to be much less expensive than demand measured during the "Peak" period. The graphic below shows the differences in the "Peak" periods between the two rates.

B7-G3 TOU Periods.png

So what does this mean for the end user? First, on the NStar B7 rate, projects that reduce peak demand tend to have high ROIs. On the NGrid G-3 rate, the only effective way to reduce costs is to reduce kWh usage through efficiency. Managing peak demand has a much lower ROI on the NGrid G-3 rate since the demand charges are relatively low. The differences in peak periods are also noteworthy as NStar shortens the peak time period during the summer months. Moving the peak period start time from 8am to 9am may allow some building operators to pre-cool facilities on hot summer days or move certain demand intensive activities after 6pm.

The graphic below should drive the point home pretty well. It shows the before and after load profile of a large building where EE improvements have reduced the afternoon peak (due to HVAC cooling load) in the summer months. As you can see, the EE measure yields very different financial results in the NStar B7 rate vs. the NGrid G-3 rate.

B7-G-3 load profile before-after.png

In summary, if you want to save money on your energy spend, look at your invoices first and figure out where the money is going. Energy Tariff Experts is a huge proponent of EE investment and believes EE is a critical part of any lean journey. That said, utility rates have lots of nuances in them and understanding these nuances is critical if your EE investments are going to deliver the ROIs that you require.

Default Gas Supply Rate Trends for New England Utilities

For most New Englanders September is a time to enjoy what remains of the warm weather, begin another season of Patriots football, and start thinking about the upcoming heating season. Early September is a great time to get your heating equipment serviced and budget for expected heating costs. Nearly all natural gas consumers in New England (except a handful of municipal systems) have the choice between the local utility and competitive gas suppliers for the commodity portion of their natural gas requirements. 

Over the last year or so, many small and medium sized natural gas consumers have realized that the default supply costs offered by the utilities are better than the offers from competitive energy suppliers. This is especially true for winter heating loads where natural gas usage is concentrated between November and March. The default supply price offered by natural gas utilities can go by many names. In New Hampshire and Massachusetts, its known as the Cost of Gas (COG). In Connecticut, its called the Purchased Gas Adjustment (PGA). In Rhode Island, its known as the Gas Cost Recovery (GCR). The graph below shows the default natural gas supply rates offered by various New England utilities to a medium size commercial customer who uses natural gas primarily for winter space heating.


Nat Gas Default Rates.png

Despite the geographic proximity of these various utilities, you'll note significant variations in the seasonal cost patterns. National Grid in Rhode Island changes the GCR infrequently and holds it steady for many months at a time. Unitil's New Hampshire gas division tends to have the highest COG due to constraints associated with the utility's geographic location and the composition of the COG. All of the other utilities tend to follow a similar pattern where natural gas supply costs go up in the fall and drop in the spring. Oftentimes, the natural gas supply cost offered by Massachusetts and Connecticut utilities is below market during the spring and summer months. This trend of below market supply costs during certain warm months has repeated itself over the last few years and is a result of the way the utilities are regulated. They are prohibited from making a profit on the sale of the natural gas commodity and instead earn their rate of return through the distribution rates. At the conclusion of the winter heating season, if they have over-collected revenues from consumers relative to the actual costs of their natural gas supply portfolio, then they will refund any overcharges to consumers in the form of below market rates until any surplus has been dissipated. 

The natural gas supply prices offered by New England utilities will reflect the broader regional natural gas price environment, but there is a lag between current market conditions and the supply rates offered by the utilities. Note that the rates for last winter do not reflect the volatility and high prices experienced in the New England spot market during that time period. In addition, although the utilities are prohibited from making a profit on the sale of natural gas to customers, they are not prohibited from engaging in prudent hedging, risk management practices, and utilization of existing long-term contracts for pipeline capacity. Existing long term contracts for pipeline capacity, when included in the utility's calculation for default natural gas supply costs, currently have the effect of reducing the winter basis component of the gas supply price relative to current market prices. Each utility is unique and this phenomena varies in its price impact on natural gas supply costs offered by each utility in the region.

For a small to medium size consumer with a natural gas load primarily driven by winter heating, the reduced cost of basis enabled by existing long term pipeline capacity contracts embedded in the utility gas supply portfolio can make the utility a better option than competitive supply (at least in this market). When a consumer gets a quote from a third party energy supplier, the quote is driven by the individual cost to serve which will reflect current basis quotes, current NYMEX natural gas quotes, and the amount of peaking and storage capacity that must be acquired to serve the account. The graph below shows the current quotes for basis swaps on the Algonquin natural gas pipeline.

Algonquin pipeline monthly basis swap price data from 9/6/2013. NYMEX OTC symbol NYMEX.B4

Algonquin pipeline monthly basis swap price data from 9/6/2013. NYMEX OTC symbol NYMEX.B4

Note that January 2014 basis is trading just below $0.80/therm. If the NYMEX contract for January 2014 is approximately $0.40/therm and capacity and supplier margin for a winter heating driven gas load add another $0.10/therm to the total cost to serve, then a typical winter heating consumer could see a quote from a competitive energy supplier of $1.30/therm for the month of January 2014. Over the course of the winter heating season, a smaller natural gas consumer with a load driven by space heating requirements will likely see quotes for natural gas supply in excess of $1/therm. While its possible that they may still beat the utility (and you'll only know this in hindsight), it's unlikely. For large natural gas consumers, competitive supply is often the better option, but for the smaller consumers who need natural gas for heating, just taking the utility default gas supply option is looking better and better.

Power Factor and Demand Charge Penalties

We've found that many people struggle to understand how Power Factor (PF) impacts demand charges. Frequently, end use customers pay a significant premium each month in demand charges because their PF is below a threshold set by the utility in the rate tariff. Oftentimes its not obvious to the untrained eye when there are extra charges associated with a bad PF on the customer bill. In this blog post, we are going to walk through PF and hopefully make it more understandable to the average commercial and industrial consumer. 


First, what is PF? We've heard all kinds of analogies that sort of make sense (e.g., head on the beer, raised wheelbarrow, etc.), but most people just sort of accept that PF exists and over thinking it is just too much work. PF is a dimensionless number, often expressed as a percentage, that reflects the relationship between kilowatts (kW) and kilovolt-amperes (kVA). A PF of one (sometimes referred to as unity) reflects a perfect PF where kW and kVA are equal. Many people find it helpful to disaggregate kW and kVA into their building block components to better understand them. We've done this below.

k = abbreviation for 1,000. 1 kW = 1,000 Watts
1 Watt = 1 Joule / sec. - (this is a measure of work done, referred to as Real Power) 
A = Ampere - (1 Coloumbe per second, this is a measure of electric current)
V = Volt - (difference in electric potential across a wire found by A * Ω where Ω is resistance in ohms)
Volt-Ampere (VA) = Apparent Power - (This is the total power supplied to the circuit. It's found by multiplying together the Root Mean Squares (RMS) of the voltage and the current. Since AC power is sinusoidal, it can also be found with this equation, VA = (Vpeak/√2) * (Ipeak/√2), but the best way to explain this concept is visually.

PF Triangle.png

On AC systems, both the current and voltage are sinusoidal. If loads are reactive, then voltage and current will be out of phase and the Apparent Power (S) will need to be greater to accomplish the same work (in Watts) as a non-reactive load. The graphic above shows this clearly. The hypotenuse shows the total Apparent Power (S) given a certain combination of real (P) and reactive power (Q). The bottom side of the triangle shows the amount of power (P) available to do Work which decreases as reactive power (Q) increases. If Q was zero, then S and P in the triangle would be equal to each other and the PF would be 1. The cosine of the interior angle in this triangle will give you the PF since the cosine of an angle is equal to the length of the adjacent side divided by the hypotenuse (remember SOH, CAH, TOA from high school geometry?). To put this triangle in real world terms, think of a reactive load like an old heavy-duty electric motor that is just starting up. The motor will dissipate a lot of energy as heat while getting up to speed and the energy dissipated as heat won't result in actual Work (in Watts). This energy lost as heat represents the reactive power (Q). The real power (P) is the kinetic energy that the motor is able to impart to do Work. The apparent power (S) is the total power that must be delivered and is determined based on the amount of the useful real power (P) and the reactive power (Q) that is lost as heat. 

Water Analogy.png

We've found that the water analogy is often a good way to explain electricity concepts to non-technical people. In thinking about reactive loads, the water wheel is probably the best illustration of the concept. Like an old heavy-duty motor, a water wheel requires a lot of energy to get going but once its moving at the same speed as the current it requires much less energy to maintain. Customer commonly ask what they can do about reactive loads and associated demand charge penalties. The answer is "it depends", but it could involve any of the following: replace the offending equipment with more modern equipment; institute behavioral changes so reactive loads are used during off-peak hours; or install capacitors. Some utilities will even help subsidize the cost of capacitors for customers with very reactive loads. The graphic below explains a bit more about inductors and capacitors.

Capacity vs Inductor.png
Excerpt from a CL&P bill for a large commercial customer

Excerpt from a CL&P bill for a large commercial customer

Now that we've fully explained PF and reactive loads, its time to talk about money and why we should care about this stuff. There are many utilities out there that charge commercial and industrial customers a penalty for having a poor PF. Anytime you see demand charges billed in units of kVA, you should know that PF is baked into the demand charge and any drop in PF below 1 results in additional billed units of demand. The graphic to the right shows a bill from Connecticut Light and Power (CL&P). In the CL&P service territory, demand is billed in kVA for large commercial and industrial customers.

Some utilities are more subtle in how they penalize customers for a poor PF. NStar's Boston Edison tariff is a great example of this. The excerpt from the tariff for the B7 commercial/industrial rate shown below illustrates how this rate charges customers the greater of their demand in kW or 90% of their kVA demand. In essence, this results in additional demand charges for all customers with a PF of less than 90%. A customer with a PF of 85% and a peak demand of (850 kW / 1,000 kVA) would pay for 900 kVA of demand, or 50 extra units of demand relative to a customer with a PF of 90% or better. For customers in areas where demand charges are high, extra units of billed demand can result in significant costs. The good thing is that most utilities draw the line around 90% PF so to make excess charges due to poor PF go away, you don't have to be perfect, just better than 90%.

Excerpt from the NStar B7 rate tariff

Excerpt from the NStar B7 rate tariff

West Penn Power (a First Energy Company) provides another example of how utilities bill customers for low PF. The excerpts from the tariff below show that the utility charges for units of reactive demand which are measured in kVars. Charges for kVars don't kick in until the measured reactive demand exceeds 35% of the kW demand. Excess reactive demand, in kVars, is charged to the customer at a rate of $0.40/kVar for all kVars greater than 35% of the kW demand. This type of billing structure is hard to follow, but customers with a good PF typically won't have reactive demands high enough to trigger these charges. Its a bit more convoluted than the NStar example shown above, but has the same effect of charging a penalty to customers with low PFs.

Excerpt from the West Penn Power rate tariff for Schedule 30

Excerpt from the West Penn Power rate tariff for Schedule 30

This stuff can be complicated, if you are struggling to understand a PF billing issue, call us. We can probably help.