Deregulated Electricity Market in Massachusetts is in Danger

Gov. Baker recently filed a bill in the MA Senate that would mandate Massachusetts (MA) Investor Owned Utilities (IOUs) to purchase nearly 40% of their supply via Long Term Contracts (LTCs) with hydropower generators (aka Hydro Quebec and/or Nalcor). Although the bill does have some provisions for participation of traditional renewable energy resources, this bill is primarily designed to favor large hydropower (and provide statutory authority for MA to participate in the multi-state Clean Energy RFP  - learn more at DPU 15-84). This bill should be extremely worrisome for any large energy consumer in MA as it will have the side effect, intentional or not, of destroying the deregulated retail electricity market in the State.

Although the bill was filed with the ostensible objective of helping MA comply with the Global Warming Solutions Act (GWSA), its important to note that the ISO-NE deregulated power market has become much cleaner over the past several years through market forces acting to close older coal and oil fired units. In essence, the market has pushed out many carbon intensive generation facilities and will likely continue to do so. As a result, State intervention isn't required to de-carbonize the ISO-NE grid as market forces, RGGI, and Renewable Portfolio Standards (RPS) have been doing the job and will continue to do so. If MA was really serious about enforcing the GWSA, they'd take a hard look at transportation policy, infrastructure, properly fund public transit, and raise the gasoline tax...........but that would require political courage and its much easier to mess with the power market b/c almost no one understands it.

Large Hydro Costs.jpg

This bill and the push for large hydropower mandates in general rests on the fallacy that large scale conventional hydropower is cheap. While hydro generation from fully amortized legacy facilities during off-peak periods may be inexpensive, firm power from new build hydro generation is actually quite expensive. Luckily, there are currently four major Canadian hydropower projects under construction that offer insightful data points as to what firm power from a new facility might cost. The table to the right shows several key data points from these four projects ($ CAD).

One thing that should be immediately clear is the big difference in capital costs between large hydro and a natural gas combined cycle generator. Intuitively, this make sense as low capital costs equate to higher operating costs and vice versa. While large hydro does have Operations and Maintenance (O&M) costs (typically several $/MWh), the amortization of capital costs are what drives the energy cost.

In 2013, ratepayers in Nova Scotia were very irate to learn about the true cost of the Muskrat Falls project which included a firm block of power and a nebulous commitment to blend in market rate power. In the provincial election in the fall of 2013, the Liberals defeated the NDP in part by tapping into voter anger and frustration with the way the Muskrat Falls Power Purchase Agreement (PPA) was handled. The Muskrat Falls project is the beneficiary of a loan guarantee by the Canadian Federal Gov't. so its clear that even with very cheap financing (backed by the Canadian taxpayer), large dam projects yield very expensive power.

Hydro Quebec is actively marketing the power from its Romaine Project, which is currently under construction, and they have been actively lobbying state legislatures in New England for inclusion of hydropower in state RPS programs. This author is old enough to remember when hydropower drew the ire of environmentalists due to the impact to salmon spawning habitat, flooding boreal forests, and displacement of First Nations people (all issues for Romaine Project BTW), but since we only focus on costs here at ETE we'll leave those issues alone. The stated capital costs for the Romaine Project appear low on a $/MW basis relative to other large hydro construction projects in Canada. While Hydro Quebec is awesome at building dams, the publicly stated capital costs may not fully capture actual costs, especially in light of the findings of the Charbonneau Commission that exposed corruption in the construction industry in Quebec including the FTQ workers (make sure to click on this one) on the Romaine Project. Its important to note that none of this corruption is the fault of Hydro Quebec and that they were a victim of the environment that forced them to buy labor peace.

Back to the electricity consumer in MA who, if Gov. Baker gets his way, will be compelled to buy massive amounts of hydropower in the name of the GWSA. The table to the right shows the results of a simple amortization model based on Hydro Quebec's stated capital costs for the Romaine Project, Hydro Quebec transmission to the US border, and the Northern Pass transmission project proposed by Eversource which will convey power from the US Border to southern New Hampshire. The table shows potential rates (in $ USD/MWh) for a PPA for firm power based on different term lengths and utilization levels of the 1,200 MW Northern Pass Transmission line. Even under very optimistic assumptions (top right), the premium to ISO-NE market priced power is substantial. As a result, its disingenuous for MA political leadership to claim that a firm LTC for new build hydro power would lower costs or even be competitive with market priced power. 

There are hidden costs to Gov. Baker's proposal since large power lines carrying electricity from far off sources are treated as important contingencies in the ISO-NE planning process. In short, ISO-NE needs to ensure that if a major leg of the system were to fail (e.g., big power plant or transmission line goes down) that it won't bring down the entire system. To mitigate this risk, ISO-NE deploys what are called spinning reserves (aka idling nat gas plants) that can ramp up and pick up load in a hurry in the event of a failure of a resource in the system. A 1,200 MW power line would be one of the biggest contingencies in the ISO-NE system and would necessitate increased natural gas burn to ensure sufficient reserves for reliability. This scenario reflects the challenges in operating Phase II, the existing major transmission line between Hydro Quebec and ISO-NE. Although its 2,000 MW, it is rarely fully loaded due to concern regarding system impacts if it went down during full utilization. The Conservation Law Foundation has written extensively on the Phase II line recently. Another hidden cost of Gov. Baker's proposal is that consumers will not reap the full capacity benefit of a LTC w/ Canadian hydro power. Quebec is a strongly winter peaking system and they've had trouble maintaining exports and serving internal load in recent years on very cold days. ISO-NE desperately needs resources that can perform in winter and ISO-NE CEO Gordon van Weile has been very clear that imported Canadian hydro power doesn't address ISO-NE's acute winter reliability needs. Hydro Quebec has made plans to bolster its system with LNG at the Becanour natural gas plant which could help firm exports (great practical idea, but carbon emissions?).

In short, Gov. Baker's hydro power proposal does not help address the needs of the ISO-NE system and will likely have the effect of further complicating it. The ISO-NE marketplace has done a great job handling the winter issues through the Winter Reliability Program which will be in place until Pay for Performance rules enter implementation in 2018. As a result, many stakeholders feels that the imminent reliability concerns have been addressed for the time being.

Gov. Baker's bill to procure up to 18,900,000 MWh of hydro power, almost 40% of the retail load served by IOUs in MA, will effectively kill the deregulated retail power market. This will take away an important hedging tool for large commercial customers and impede innovation in retail energy markets, products, and smart grid strategies (e.g., price response, etc.). If enacted, the costs for this hydro mandate will most likely be borne by a non-bypassable line item charge on the customer's bill. A quick back of the envelope indicates that the costs won't be pretty. 

Right now, wholesale power in ISO-NE is running around $50/MWh on an annualized basis. Power is cheap in summer, but expensive during peak winter months. If a firm LTC for hydro power runs $85/MWh, then that premium of $35/MWh x 18,900,000 MWh = $661,500,000. In a state of approximately 6.7M people, that cost premium comes out to about $100 per person per year. This is a significant cost premium to pay for a non-local and non-zero carbon resource. Are we comfortable making this expenditure and the trade offs against local renewables and energy efficiency that it entails? Are we comfortable with more energy intensive manufacturers (e.g., ETE's clients) leaving MA and taking their jobs with them due to high energy costs? Can't we buy more Quebec hydro power on a spot basis without a LTC? Is elimination of the retail power market in MA a sound policy choice?

If this legislation is enacted as proposed, the MA retail electricity market will look very much like the dystopian nightmare that the Ontario electricity market has become. Wholesale electricity prices in Ontario are very low, but retail prices to consumers are very high. This is the result of layers upon layers of out of market PPAs and mandates that has rendered the Ontario wholesale price to be meaningless from the perspective of the retail customer. Wholesale power costs in Ontario typically comprise less than a third of the total bill and most third party energy suppliers have abandoned the Ontario electricity marketplace since hedging wholesale market exposure has become pointless. This legislation will push MA in that direction.

In summary, its terribly frustrating to see a Republican Governor, who should support markets, propose legislation that will effectively repeal electric industry restructuring and take away an important cost management tool for retail electric consumers. As the electric industry is on the precipice of a massive transformation, retail markets are critically important and deliver significant benefits to commercial consumers.

Halloween Post: PSNH and the Zombie Tariffs

While there are many horrific and ghoulish stories that we could write about in the energy sector, we recently came across a textbook version of a nightmare that plagues many a utility rate department: the zombie tariff. Zombie tariffs are rates that just won't die despite the best efforts of the utility to kill them. The graphic below illustrates many of the zombie tariffs that you'll find in the haunted utility tariff book

Zombie tariffs are often really hard to kill. The reasons are many, but most often utility commissions are sympathetic to customers who have "exercised reliance" on the existence of these rates. Oftentimes, these customers made investments that would be stranded if the rate were to go away. Commercial and industrial users on zombie tariffs often intervene in rate cases to ensure that their zombie rate lives on.

About two weeks ago, this author was taking a look at the latest filings with the New Hampshire Public Utility Commission (NH PUC) when we came across Docket 14-203. This docket embodies the nightmare that zombie rates can pose for a utility rate department. Once upon a time in the PSNH territory, before many of us were born, PSNH offered a special discounted rate for customers with controllable hot water heaters. The deal was discounted electric service in exchange for installation of a control device that would ensure off-peak only operation of the heating element. This rate was actually a Rider to the residential rates called the Controlled Water Heating (CWH) rider. It was closed to new customers in 1981 and customers were grandfathered until they replauced or removed their hot water tanks, at which time they would be removed from the rate and defaulted to standard rates. Somehow in 2014, mindbogglingly there are functional water heaters from the 70s on this rate that still work (but I bet some customers replaced their tanks and just didn't tell PSNH). The graphic below shows a timeline of this rate and summarizes the results of the PSNH investigation into customers still on the rate.

PSNH had a real interest in vetting customers on this rate because most of the metering and control devices for these customers were made before 1980 and aren't available for purchase anymore. Furthermore, PSNH found that the load control functionality of many of these meters was no longer operable and many meters weren't working properly. PSNH's metering team found itself in a ghoulish place faced with the following three options detailed below.

The NH PUC judiciously allowed PSNH to proceed with option three as the control functionality on these water tanks isn't worth three hundred thousand bucks. Its important to note that while the metering and controls for Rider CWH will be scrapped, the tariff will live on like the undead zombie it is. While it will no longer terrorize the metering department at PSNH, it will continue to haunt the dreams of the rate department, especially when things like cost of service studies and revenue requirements need to be devised. Chances are, Rider CWH will continue for many more years.............muahahahaha.

Happy Halloween!

A Post for our Friends at Tank Utility

At ETE, once in a while we run into propane when we have clients who are off the gas grid or have propane as an alternate back-up fuel. One of the things that we've always found frustrating is the opacity of retail propane prices. In this post, we are going to talk about wholesale and retail propane prices and then discuss TankUtility, an exciting start-up run by a former colleague from this author's days at EnerNOC.

Graphic from brochure on National Propane Gas Association website available  at this link .

Graphic from brochure on National Propane Gas Association website available at this link.

Propane is a by-product of natural gas production and oil refining. You may hear people talk about wet gas and dry gas. Wet gas is natural gas that has a high content of Natural Gas Liquids (NGLs) such as butane, propane, etc. The EIA graphic to the right succinctly displays how propane gets to your tank from the wellhead or refinery. You'd think that we'd be sloshing in propane these days thanks to the shale gas revolution and in some places we are, but others still experience winter scarcity due to infrastructure constraints.

There are two propane futures contracts with delivery points at Conway, KS and Mount Belvieu, TX. Mt Belvieu happens to be at the beginning of the TEPPCO pipeline that ships propane to the Northeast with a terminus at Selkirk, NY. At ETE, we get propane prices at Selkirk as part of our subscription to weekly OPIS rack rates for liquid fuels. Generally, Selkirk trends about 20 cents per gallon above Mt. Belvieu, but honestly wholesale prices don't mean much to the retail end user as retail costs are at least double posted wholesale prices.

Historically, retail propane has been priced relative to No. 2 heating oil for consumers since that is its main competition for space heating. The EIA has some great data regarding historical propane prices (check it out here) and I took some of that data to illustrate the price trends of retail propane in ME, VT, and MA vs. the New England average retail cost for No. 2 Fuel Oil. To make an apples to apples comparison, we adjusted the No. 2 Fuel Oil price data to gallons of propane equivalent. No. 2 fuel oil has ~ 138,000 BTUs per gallon while propane only has 91,000 BTUs per gallon. To compare No. 2 Fuel Oil to propane, we multiplied the EIA prices by 0.6594 (91,000/138,000). As the graph shows, the correlation between Fuel Oil and propane has weakened a bit in recent years and the volatility in propane prices seems to have increased along with price spreads between adjacent markets.

You may have noticed in the graph above that propane prices went totally nuts during the winter of 2013-2014. Although it was a cold winter, the price spike wasn't entirely attributable to cold weather. Things started to go off the rails when the 2013 corn harvest was especially wet, requiring huge amounts of propane to dry the crop. As a result, the winter started off with much lower supplies than normal. Delivery infrastructure in New England severely constrains the ability to rebuild stocks quickly. This article from the Portland Press Herald provides a fantastic overview of last winter's supply constraints. Although New England can have peak winter scarcity conditions for propane, other parts of the US are beginning to export NGLs (propane and others), but that propane can't come to New England thanks to the Jones Act. This is beyond stupid, but isn't a problem that we can fix here at ETE. 

Graphic from NYSERDA Presentation "New York Propane Market Fundamentals 2012-2013 Winter Season" Matthew Milford, Dec 7, 2012. Available at  this link

Graphic from NYSERDA Presentation "New York Propane Market Fundamentals 2012-2013 Winter Season" Matthew Milford, Dec 7, 2012. Available at this link

The graphic to the right shows the regional propane storage infrastructure. The storage facilities in Providence, RI and Newington, NH are typically refilled by foreign tankers (see Jones Act comment above) when New England wholesale propane prices are competitive globally. Other smaller storage facilities are refilled by rail with most of those propane supplies originating in Canada.

Graphic taken from MA DOER heating fuel price survey, available  at this link

Graphic taken from MA DOER heating fuel price survey, available at this link

So, how does this relate to TankUtility? A common lament of retail propane users is that the prices they pay for propane can be significantly different than the prices reported for their region. Massachusetts and Maine (and a few other states) do a great job collecting price data for heating fuels, including propane, during the winter heating season. At ETE, we've always been stunned by the range in prices between the high, average, and low prices reported for propane. The graphic from the MA Dept. of Energy Resources illustrates this clearly. There is a difference of over $2/gal between the reported high and low prices in their retail price survey. While its reasonable to expect differences due to fill size, travel time, etc., a spread of $2/gal is too high for an efficient market. 

So what is a propane user to do? First, you should buy your own tank and get one that is large enough to get you through an extended cold snap. The TankUtility mobile app allows you to get quotes for propane delivery from multiple suppliers. The opportunity for price discovery is a huge win for the consumer in what is an otherwise opaque market. It can also be a big win for propane suppliers who are able to effectively manage their supply portfolio as they'll get an opportunity to compete on price and win new business. While the TankUtility product is cool in other ways (e.g., not having to go check your tank when its zero outside), we think the price discovery aspect of the product is the coolest part.

At ETE, we are always pro-consumer and pro-efficient markets and we think our friends at TankUtility are onto something. As I write this, they are trying to raise some money on KickStarter and if you are propane user, I encourage you to give them a look. 

Manage Capacity Tags with GridReason

We've been meaning to write this post for a while about a very exciting new company out there called GridReason, founded by a former colleague of this author. To date, most Critical Peak (CP) prediction services have been driven by models that rely, at least in part, on daily human judgement to determine the risk of an occurrence of a peak load event.. This author has designed and/or managed such programs for ISO-NE, ERCOT, and Ontario.

As a quick refresher, a CP is an interval when a system reaches peak load for a given period. You may hear terms such as 1 CP, 5 CP, or 12 CP bantered about. When you hear the term "1 CP", it refers to a single critical peak which is the peak load interval for a system during a given period. Oftentimes this period is one year. By the same logic, 5 CP would be the five highest load intervals in a given period. In New England, you may hear 12 CP since ISO-NE Transmission charges are calculated based on monthly system peaks and there are 12 months in a year (but Trans cost allocation is way too complex for this blog post). A Coincident Peak refers to the load of a customer during the system CP interval(s). Capacity Tags are assigned to end use customers based on their Coincident Peak(s) and determine the amount that they will have to pay for capacity on the supply portion of their bill.

Anyone who works in deregulated energy markets should understand how capacity charges are allocated based on CPs. The table below provides a brief overview of the markets where costs are allocated to end users based on usage during CPs.

Once an end user understands how their capacity tags are set, they can decide if they'd like to actively manage them. The decision to manage capacity tags is largely driven by opportunity costs and operational flexibility. A company making a low margin commodity product may have a low opportunity cost of interruption and would be happy to drop load during potential CP hours in exchange for the ability to reduce their electricity spend. To the contrary, a pharmaceutical plant or a Just-in-Time manufacturer has a very high opportunity cost of interruption (batches get junked, schedules get blown) and would typically be unsuitable for a capacity tag management program.

For those who can manage their capacity tags, GridReason becomes an awesome resource. They've developed powerful statistical algorithms to predict the likelihood of a CP event and are available at a fraction of the cost of existing predictive services. If you are curious to learn more about managing capacity tags and their offering, call them up and tell them ETE sent you.

If you'd like to learn more about capacity tags, how they work, and what capacity costs in various deregulated markets, please call us. We'd be happy to give you a proposal for whatever information you are looking for.

PJM Capacity Charges & Energy Storage Economics

There has been a steadily growing buzz around energy storage in PJM. Battery storage is increasingly participating in the frequency regulation markets and PJM recently conducted a stakeholder session to investigate participation of battery storage in the Base Residual Auction (BRA) capacity market. Despite this, many energy storage firms focused on behind the meter installations don't fully take into account the value of avoided retail capacity charges for the end use customer. It is much simpler to help an end use customer avoid capacity charges than it is to bid into the BRA.

As a quick refresher, PJM has a Generation Capacity cost allocation mechanism where retail customers are charged a Capacity Charge based on their usage during the peak load hours of PJM's top five highest load days, referred to as 5CP hours. This charge is called the GenCap charge and it can be broken out separately on an invoice by deregulated electricity suppliers or rolled into a fixed price. Regardless of who you purchase electricity from (e.g., utility vs. deregulated supplier) the GenCAP charges are there. On June 1, 2014, all PJM customers have their GenCAP tags reset based on their usage during the 5CP hours from the previous summer. The graphic below shows PJM's load pattern from the summer of 2013, with 5CP days shown in red. The table to the right shows the highest load hours on each of these days.

For an interval metered retail customer, their GenCAP tag will be based on their actual metered usage during the 5CP intervals. The table below illustrates how this tag is determined. There are a couple of additional scaling factors that may be applied, but this table captures the essence of the GenCAP tag calculation.

Once the GenCAP tag has been determined, it is multiplied by the PJM zonal capacity clearing price to determine what the customer must pay for capacity. The table to the left provides a simplified depiction of the costs associated with a GenCAP tag of 845 kW in the PSE&G - North PJM capacity zone. As you can see, the customer could realize a significant savings opportunity if they were to drop their load to minimal levels during PJM 5 CP hours. Predicting the PJM 5 CP hours is actually fairly straightforward as PJM's load is strongly weather driven. Really hot days = PJM peak loads. This author has built prediction tools and there are several services that provide daily forecasts for PJM during the summer season. Viridity, Gridreason, and EnerNOC provide these predictive services.

In PJM , the Transmission Capacity charge offers another ~ 20k of cost avoidance opportunity per MW, but its calculated a little differently from GenCAP.

If you'd like to know more about these topics, please call us, especially if you are trying to sell behind the meter battery storage as capacity charge avoidance is a significant value stream that is poorly understood and often overlook by storage system developers.

Power Plant of the Week - Sir Adam Beck Generating Station

Sir Adam Beck Generating Station, photo obtained from Ontario Power Generation website at Sir Adam Beck 1 is on the right, 2 on the left.

Sir Adam Beck Generating Station, photo obtained from Ontario Power Generation website at Sir Adam Beck 1 is on the right, 2 on the left.

What better way to celebrate Canada Day 2014 than by taking a close look at one of Canada's most impressive energy infrastructure projects. This post focuses on the Sir Adam Beck Generation Station at Niagara Falls. Sir Adam Beck was a politician and businessman from London Ontario who was a strong proponent of publicly owned power systems. He persuaded Ontario Premier James Whitney to create and appoint him head of the Hydro-Electric Power Commission of Ontario (predecessor of the late Ontario Hydro). In 1917, the Commission commenced the construction of the Queenston-Chippawa Hydroelectric Plant which included a canal beginning at the confluence of the Welland and Niagara Rivers, traversing through the City of Niagara Falls, and ending at the hydro station known today as Sir Adam Beck 1 (facility was renamed in 1950). The first turbine went operational in 1922 and by 1925 the project was complete with a combined generating capacity of nearly 500 MW. This was the world's first Mega-hydro project and resulted in several technology innovations in dam construction.

This project was influential in shaping American energy policy of the 1920s and 30s as Sen. George Norris, the patron of American Public Power, repeatedly used the price discrepancy between power prices in upstate NY and the Niagara Peninsula of Ontario to demonstrate the benefits of public ownership. At the time, Ontario enjoyed much lower electricity prices than areas of New York served by Investor Owned Utilities. 

After World War II, the facility was significantly expanded with two diversion tunnels constructed under the City of Niagara Falls and a second generating station added. The facility expansion was dubbed Sir Adam Beck II and represented almost 1,500 MW of new capacity, coming online in 1954. You can find some really cool photos of construction at this link. A few years later, a 174 MW pumped storage facility was added so that the plant could more flexibly respond to the daily load peaks.

Big Becky tunnel boring machine breakthrough photo obtained from OPG website. 

Big Becky tunnel boring machine breakthrough photo obtained from OPG website. 

In 2005, Sir Adam Beck II was upgraded by Ontario Power Generation (OPG) adding 194 MW and creating an opportunity to increase generation and more fully utilize Canada's water allotment from the Niagara River. In the mid 2000s, OPG commenced boring a third tunnel under Niagara Falls to bring more water to Sir Adam Beck II. Big Becky, the largest tunnel boring machine in the world, worked 20 hour days for six years boring a tunnel ~ 45 ft in diameter. Breakthrough occurred in May 2011, concrete pouring finished in Nov. 2012, and commercial operations commenced in March 2013. Although the project did go a couple hundred million loonies over budget (total cost ~ $1.5B CAD), the rock was much harder than expected and this was a pretty challenging endeavor. Given other recent fiascos in the Ontario energy sector, ETE considers this project a resounding success.

Each phase of the The Sir Adam Beck complex is noteworthy for a variety of reasons, but one standout aspect of this project is the international cooperation around water allotments. The Niagara Treaty of 1950 specifies minimum flow levels over Niagara Falls that must be maintained and there is a Joint Commission that governs the management of the water resource along the Niagara River. It's a great model for international cooperation around natural resources and a symbol of the friendship between the US and Canada.

Lets look at an Electric Vehicle Tariff

Energy Tariff Experts (ETE) was founded by a guy who loves cars and utility tariffs. In kindergarten, ETE's founder gave a presentation on Chrysler's 1985 model year line up for show and tell and his interest in cars hasn't abated since. As a result, analyzing Electric Vehicle (EV) tariffs is about the most fun we can have over here at ETE. In this post, we are going to take a close look at Baltimore Gas & Electric's (BGE) Residential EV pilot tariff and discuss how it is different from the standard residential rate.

Many utilities see EVs as a way to improve the load factor of their systems and tariffs that incentivize off-peak charging are one way for utilities to encourage consumers to charge their EVs at night or during low load periods (e.g., weekends, holidays, etc.). Often, utilities are constrained in their tariff design options by the capabilities of their billing systems so they are rarely able to make up a rate design that is totally different from existing rates. The graphic below shows the Time of Use (TOU) periods for BGE's standard TOU rates and the residential EV pilot rate. The EV pilot rate is available to residential consumers who own and charge an EV at their residence. The big difference in the EV Pilot rate is that the intermediate period is treated as an off-peak period.

The BGE residential EV rate distribution charges for usage and the monthly customer charge are actually identical to those for the non-TOU standard residential rate. BGE uses the supply portion of the bill to provide the off-peak discount in the energy charges. You can check out BGE's current supply rates at this link. The table below compares the standard residential rate structure with the residential EV pilot rate. For simplicity, the table leaves out many of the Riders that are used to adjust the distribution base rates so this table may not match an invoice perfectly.

As you can see, the off-peak charging rate on the EV pilot tariff represents at discount of approximately $0.03415/kWh off the standard non-TOU residential rate, but the peak charges are significantly elevated. This rate requires the customer take supply service from BGE, so it precludes competitive supply (which may or may not be less expensive than BGE per market conditions). For a consumer to make an educated decision regarding opting into the EV pilot rate, they would need to evaluate their current domestic electric usage (e.g., appliances, water heater, HVAC, TV, etc.) that occurs during the peak period relative to their off-peak consumption and expected EV charging needs. For someone who is a heavy EV charger, this rate may offer savings, but for the casual EV charger with significant household electric consumption during the peak periods, this rate could end up being a wash or a money loser. Consumer behavior and consumption patterns will determine the savings opportunity from this rate.

In summary, BGE's residential pilot EV rate is fairly typical of utility EV rates in that it conforms to the limitations of the utility's billing system and provides a discount for off-peak consumption. If you have a project related to EV tariffs and need some help, please call us. We'd love to give you a proposal.

The Utility Death Spiral is Rubbish

These days, its common to hear renewable energy scenesters talk about the utility death spiral. At Energy Tariff Experts, we are confident that there is no death spiral. There may be some stress, but certainly no death spiral. In this post, we'll explain why this is the case.

It all begins with rate design. If you are a huge energy geek, you must read "Principles of Public Utility Rates" by James Bonbright, which is basically the foundational work on rate design. In essence, rates should be aligned with the costs of service and the various cost drivers in the system should be identified with rates constructed to charge for the costs that users impose on the system. Unfortunately, many utilities have rates that are a muddled mess, (at least from a cost accounting perspective), and do not reflect the true costs of providing service. Many rate structures exhibit serious cross subsidization and free ridership run amok. Rates based on kWh exemplify this as the marginal cost of distribution is driven by demand, not usage. 

Utilities must size the distribution infrastructure to be able to meet peak demands, even if those peaks occur once a year. The larger the sizing, the more expensive it is. Demand charges capture these costs, but kWh charges do not.

Utility rate design is an exercise in cost accounting and proper rates will reflect the cost to provide service, regardless of whether the system is summer peaking, winter peaking, or has lots of distributed generation or none. The graphic below provides a simple way to think about how utility costs should be captured in rates.

Utility Cost Drivers.png

As the graphic shows, utility costs can be grouped into those that are nearly fixed, vary with peak demand, and those that vary with usage. Utility cost items should be associated with utility charge types (monthly customer charges, demand charges, and usage charges) based on the degree to which customer behavior influences the utility cost to serve. For instance, the costs for the meter should be recovered in the customer charge since the cost to the utility to own and operate the meter do not change based on usage. The costs for the local distribution circuit should be recovered through demand charges, since it must be sized to accommodate the maximum rate of customer consumption.

When people talk about the utility death spiral, they incorrectly assume that the utility rate structure is static and based upon kWh. This is a misconception. Historically, utilities have billed in kWh because electro-mechanical watt hour meters were inexpensive and demand capable meters or interval meters (MV-90 bro) where too expensive to use for small commercial or residential customers. As a result, the legacy rate designs we see today are holdovers from times when utilities could only economically measure kWh for small customers.

As SmartMeters slowly become ubiquitous, the ability to measure and bill for consumption by time of use, seasons, or by peak demand becomes possible for small customers. Although utility rate designs only get a refresh once every two decades (or longer), distributed generation is forcing many utilities to take a serious look at their rate designs. While some have proposed ham-handed fees such as standby charges (which are totally lame) others are looking at increasing the ratio of fixed monthly charges and demand relative to usage charges. While people might push back at this, many other utilities have gone in this direction. Your cell phone bill is no longer based on the number of minutes you use, your cable bill is a fixed monthly charge, your telephone landline (if you still have one) is mostly fixed. Expect electricity rates to move in the direction of fixed charges as DG becomes more prevalent. 

Those foretelling the death of the electric utility also forget that utility regulators need to ensure the financial health of the regulated electric utilities since most states have a regulatory framework that ensures reasonable rates of return provided service quality metrics are met. As a result, regulators will grant utilities their revenue requirement even if the rate base is shrinking. The loss of one massive customer is much more damaging to a utility that 1,000 cuts from distributed generation (see BGE's Sparrow's Point Rider for proof)

While utilities can move to change their rate designs, albeit with painfully slow regulatory lag, some people say that we'll see a mass defection of customers similar to what has happened to the landline phone companies. This is complete nonsense because while a few large sophisticated consumers may install micro-grids, 99% of customers will not. Furthermore, for those of you talking about mass defection from the grid, go off grid.......I dare you..........because I know you won't leave since you like electricity to be there reliably when you need it.

Massachusett's SREC-II Program is in the Crosshairs

Remember a few months ago in our blog post "The RECS are too Damn High" when we said to expect a major fight in the MA legislature over raising the net metering caps? Well it's here and it's getting ugly. We'll start with a little background and then dig into the current state of affairs which are volatile and subject to change.

In early 2014, Representative Frank Smizik, a solar friendly Democrat from Brookline, introduced House Bill 3901 which would have removed the caps on net metering through 2016 and mandated a commission to study the costs/benefits of net metering, etc. A similar bill, Senate Bill 2019 was introduced by State Senator Anthony Petruccelli. The solar industry cheered, but rumors quickly began swirling that the utilities were going to file a competing bill. In March 2014, they did when S.B. 2030 was filed by State Senator Michael Rodrigues with the ominous title "An Act reducing the cost of solar power through increased competition."

Fast forward to June 2014 and we have House Bill 4185. This bill was developed in closed door sessions by the utilities, MA DOER, and selected renewable energy stakeholders. The table below includes a brief synopsis of the provisions of the bill (although its possible there are some Easter eggs in here that we aren't catching at first glance).

This bill has really split the solar community in MA. On one side is the Solar Energy Industries Association (SEIA) and the New England Clean Energy Council and on the other is the Solar Energy Business Association of New England (SEBANE) and SREC aggregators like SREC Trade. The big takeaway that we take from this is that if you are planning any significant solar project in MA, you need to stop and wait for this process to play out. We think the residential and small commercial markets will be fine, but the impacts to the economics for larger (60+ kW) SREC-II based projects in the proposed SREC-II wind down period are unclear and it's hard to tell if this new regime will be better or worse. Our take is that compensation rates will go down, but financing might be easier and more predictable. 

This turn of events isn't entirely surprising as the utilities strongly expressed that central procurement/feed in tariff programs were their preference, but it is disappointing. The SREC-II program was the result of more than a year's worth of stakeholder input facilitated via a structured MA DOER process. It is now being dismantled by legislation that was crafted by a select group of insiders behind closed doors. We don't doubt that the proposed new solar regime in this legislation will be less costly (based on CT's ZREC experience and RI's current Feed in Tariff), but solar will get built more slowly and cynicism will reign regarding the regulatory climate in MA. What's the point of participating in a lengthy development process like SREC-II if it will get dismantled by legislation less than 4 months after going live? At a minimum, our take away is that its important to have good lobbyists on Beacon Hill, because if you aren't paying attention, something bad will probably happen to you.

Can Solar Help Me Avoid Demand Charges?

In this blog post, we are going to take a closer look at demand charges and the impact that an on-site solar PV system may have upon them. While many people simply assume that their measured demand will be reduced by the average output of the PV system, they are often disappointed to find that this is not the case. The amount by which solar PV systems reduce demand charges are influenced by a variety of factors and we are going to explore several of them in this post where we will take a close look at a customer behind Southern California Edison (SCE). 

As a quick refresher, SCE determines demand, in kW, based on the maximum 15-minute rate of consumption. For rate TOU-8, demand is measured on a 24x7 basis to determine the facilities demand charge and separately measured during the mid-peak and on-peak periods to determine the demand charges for these respective periods. The on-peak period only exists during the summer months of June - Sept. The graphic below shows a screenshot of an SCE invoice and identifies each demand charge. 

As you can see, the on-peak demand charge during this billing cycle is significant at $22.99/kW and even a modest reduction in on-peak demand will yield significant savings. Since the SCE on-peak period is defined as noon - 6pm on summer weekdays, you'd think that solar PV would be a sure thing to reduce this charge. Sometimes it is.......and sometimes it isn't as we'll see below. The first graph below shows a month where the solar PV system performed consistently and reduced the on-peak demand by about 500 kW from what it otherwise would have been. Given current on-peak SCE demand charges of $25.33/kW (June 1 2014 tariff), this reduction of 500 kW would yield a savings of $12,665 for this billing cycle. Note how this load profile is classic "Duck Curve" and how easy it is to distinguish between weekdays and weekends. 

The X axis shows hours 1 - 24 and the Y axis shows hourly kWh usage. Each line depicts the hourly load for a given day of the month and the legend to the right shows the line colors associated with each day.

The X axis shows hours 1 - 24 and the Y axis shows hourly kWh usage. Each line depicts the hourly load for a given day of the month and the legend to the right shows the line colors associated with each day.

The graph below shows July '13 where a couple of cloudy afternoons ruined the demand charge savings for the month. You can see a handful of days where the load rebounds between 3 - 4pm to about 2,900 kW when solar output is diminished due to cloud cover. Although there are still some savings relative to where the load would be without solar PV, the savings in demand are significantly less than the average output of the PV system.

The X axis shows hours 1 - 24 and the Y axis shows hourly kWh usage. Each line depicts the hourly load for a given day of the month and the legend to the right shows the line colors associated with each day.

The X axis shows hours 1 - 24 and the Y axis shows hourly kWh usage. Each line depicts the hourly load for a given day of the month and the legend to the right shows the line colors associated with each day.

As this example demonstrates, even when a utility has an on-peak period that coincides with solar PV output, demand charge savings will still exhibit a high degree of variability from month to month. As a result, savings from demand should be treated as extra gravy, but the basis for any financial analysis around behind the meter PV has to be driven by avoided kWh charges. These are more certain (presuming your solar PV system works properly) while reductions in demand can be fickle.

If you have questions about this stuff, call us.

MA SREC II Update: The RECs Are Too Damn High

Its been awhile since we've provided an update on the rule making process in Massachusetts (MA) for the successor solar program to the Solar Carve Out (SREC I). The successor program under development is referred to as SREC II. Before we begin, a little background may be helpful. In early 2013, it became clear that the SREC I program was going to reach its program goal of 400 MW ahead of schedule. The MA Department of Energy Resources (DOER) began a public stakeholder process to create a successor program which is nearing its conclusion. There have been several proposals submitted for public comment and DOER issued draft regulations approximately six weeks ago. DOER will now take the input received from stakeholders in the most recent comment period and incorporate select comments into the final regulations. These final regulations will then be sent to the MA Joint Committee on Telecommunications, Utilities, and Energy for comment. The Joint Committee will then provide comments to DOER which will be incorporated into the final promulgated regulations that will take effect. DOER has made a webpage available where they have provided information on the process and regular updates.

Instead of ETE recapping the latest version of proposed regulations for the SREC II program, I'd recommend you read this summary on It captures most of the important points of the new program design and ETE will use this blog post to focus on the process used by DOER in this rule making and our expectations regarding likely outcomes. 

In order to inform the process for creating the SREC II program, DOER hired a consulting team (Sustainable Energy Advantage, Meister Consultants, La Capra, and Cadmus) to produce several reports. The purpose of these reports were to provide an informed basis for the SREC II policy design and also to justify the levels of incentives required for various types of solar installations. You can download these reports from this DOER webpage. Although ETE is going to present information from various intervenors that are critical of these reports, ETE's feeling is that they were well done with the exception of report 3b. The shortcomings in report 3b, entitled "Analysis of Economic Costs and Benefits of Solar Program", in ETE's opinion, are largely due to a pre-determined outcome requested by the client (DOER) and a scope that wasn't sufficient to perform a fully comprehensive benefit to cost ratio for MA ratepayers. Although its easy to blame the consultants, the process wasn't designed to deeply vet the costs of solar. More on this later.

Although utility, ratepayer, and environmental groups have been voicing concerns about the expected costs and issues with the SREC II program, they became quite vocal during the January 2014 public comment period (download the zip file 1/3 of the way down the page). A quick summary of each type of intervenor and the nature of their comments are listed below.

Environmental Groups - Groups such as the MA Audubon Society, various municipal conservation commissioners, and clean water groups are very worried about forests and wetlands being cleared for ground mounted solar arrays. The restrictions and discounting via SREC factors of ground mounted solar arrays largely stem from environmentalists who are upset (rightly so) that many large ground mounted arrays have been built on sensitive ecosystems over the last four years, often exploiting agricultural zoning to build structures that would otherwise be prohibited.

Solar Developers - Although their comments were wide ranging, an important theme focused on the restrictions on managed growth. In late spring 2013, large scale solar development in MA came to a screeching halt when the SREC I program became oversubscribed. By many estimates, there are nearly 100 MW of shovel ready solar developments waiting to move forward and most of these would fall into DOER's managed growth category (500 kW ground mounted). The regulations state, in 14.05(9)(m)(1) that the managed growth category will accept 26 MW in 2014 and 80 MW in 2015. Stakeholders are concerned, and rightly so, that this is not enough capacity to accommodate the existing development pipeline for larger systems and will unnecessarily put a brake on solar industry growth.

Retail Energy Suppliers - The Retail Energy Supply Association (RESA), TransCanada, and ConEd Solutions all had critical comments. TransCanada provided a strongly worded, yet well-reasoned, take-down of DOER's 3b study regarding benefits of solar to ratepayers. ConEd Solutions argued that the SREC factors result in wasted RECs, arguing that a managed growth system receiving an SREC factor of 0.7 results in the wastage of the remaining 0.3 MWh that should be credited as a Class I REC. RESA focused on the uncertainty regarding future SREC forecasts, petitioned for more transparent forward looking SREC compliance forecasts, and highlighted the risk premiums borne by ratepayers as a result of the uncertainty regarding SREC purchase obligations for retail suppliers in future years. They also highlighted DOER's recent activities that have heightened uncertainty and risk premiums for retail suppliers in the marketplace, such as the June 2013 "emergency" regulations to deal with the over subscription of SREC I. They aren't the only ones berserk over DOER's perceived abuse of "emergency" regulation making.

Utilities - Northeast Utilities (NU) and National Grid both weighed in with several comments on the proposed SREC II framework. National Grid has been vocal in airing its concerns regarding the costs of the program and used the December 2013 Raab Roundtable to propose an alternative approach where the utility would have a tariff based solicitation that would ensure stable and predictable revenues to a solar installation for a period of ~ 15 years and align the payment rates with the revenues required to secure financing. National Grid has been using this model with success in Rhode Island and has been able to procure solar at much lower costs than those envisioned in the SREC II program. NU goes further than National Grid and states that the SREC II program is not a market for RECs, but instead a contrived construct that will keep SREC costs artificially high. They shred DOER's 3b report regarding the cost benefits of solar. Specifically, NU states that the estimated avoided transmission cost benefits from solar development are inaccurate because they are lifted out of a study regarding avoided transmission and distribution costs associated with energy efficiency (EE), which is inappropriate for solar since EE resources tend to be coincident with system peak loads and solar is less so. NU also correctly notes that many systems installed in places without onsite load (e.g., ground mount) result in increased transmission and distribution costs associated with interconnection. NU explained that their experience in Connecticut with the LREC/ZREC program illustrates that a long term REC contracting regime lowers the cost to acquire solar resources relative to the proposed SREC II framework. 

Our thoughts - It appears likely that the regulations will be implemented in something very close to their current form. There are a number of key takeaways regarding the future of solar in MA.

  • There will be a knockdown drag out fight over net metering later this year as the statutory net metering caps for each utility will be reached soon. The National Grid presentation at the Raab Roundtable in Dec. 2013 hints at this, but the utilities are adamant that distribution generation be sized according to the on-site load. In addition, any expansion of Virtual Net Metering credits for ground mount systems will be less generous that the current regime. Expect some very solar friendly legislation that expands the net metering caps in the MA Legislature that quickly becomes contentious.
  • SREC II will be limited in its ability to build out new MWs of PV if the net metering issue isn't resolved quickly
  • The Solar Clearinghouse Auction is a price support mechanism, NOT a floor price, how in the world don't people understand this???
  • The SREC Factor approach discards a portion of the REC that would otherwise qualify as a Class I REC. The dual minting approach was included in prior iterations of DOER's SREC II proposal and our guess is that it was discarded due to complexities in implementation in the NEPOOL GIS attributes tracking system used to mint and retire RECs.
  • The current MA approach to solar is very customer friendly in that anyone can go solar. Your average customer can look in the Yellow Pages for solar installers, get multiple quotes, and then move forward based on their own purchasing process and timeline. In the auction procurement methods proposed by National Grid and NU, the customer needs to partner with a developer in order to submit a bid to the utility. In the MA model, the customer is in the driver's seat whereas in the auction model the customer is captive to the solar developer unless they are highly sophisticated. 
  • New Jersey and Maryland are both seeing new solar PV builds with SREC prices below $200/MWh. What are they doing differently and why shouldn't MA copy them?
  • The MA DOER has a lever to reduce costs three years into the program in that they can reduce the SREC factors per section 14.05(9)(l)(4) of the proposed regulations. 

What will this cost you?

2015 Forecast RPS Costs.png

The SREC II will look very similar to SREC I in that it is a carve-out of the Class I Renewable Portfolio Standard (RPS). By 2015, SREC I compliance costs will have stabilized and SREC II compliance costs will be starting to creep into the supply portion of your electricity bill. Section 14.07(3)(d) states that the 2015 SREC II compliance obligation for electricity suppliers will be 161,958 SRECs which translates to 8/10 of a mil per kWh in extra supply charges. This isn't a big deal for the average residential ratepayer, but if you are a hospital, data center, or large industrial this will be a noticeable cost. In the table to the right, we've broken down the expected cost impact of the MA RPS in 2015 when SREC II will begin to show up in consumer supply charges. Although SREC II doesn't seem all that bad, it will continue to grow and the overall RPS charges will be near a penny per kWh by 2015.

In recent weeks, there have been several articles in the MA press that have been critical of the costs associated with expansion of solar. Commonwealth Magazine ran a story regarding how certain prominent politicians are ducking the issue and even the Globe ran an article that aired the cost concerns of many stakeholders. So far, the debate hasn't devolved into an emotional screaming match........yet.

In summary, we like the decentralized approach to solar taken by MA as opposed to the more centralized programs in RI, CT, and NY, but the costs of SREC II seem higher than warranted. New Jersey is a similar state in many respects (at least from a cost perspective) and they are building out solar at a steady rate at lower costs. Most of DOER's market design is thoughtful, but we think they need to exert more cost pressure on the industry. As we've stated in the past, renewable energy costs money and MA's decision to transition to a more renewable generation mix is a policy choice, endorsed by MA voters, and embraced by politicians that has associated costs and benefits. The benefits are cleaner air, the costs are buried in your electric bill. The only way to dodge these costs is to go solar yourself and get on the receiving end of these programs. 

Power Plant of the Week - Fore River Generating

Anyone who lives on the South Shore of Massachusetts knows the Fore River Generating plant. It's on the east side of the Fore River in Weymouth, MA, immediately south of the Rt. 3A bridge. The plant is a modern combined cycle facility that consists of two natural gas combustion turbines that both feed a steam turbine. In total, the plant has a summer capacity of approximately 700 MW and is run as a baseload or intermediate load following plant depending on natural gas prices. The natural gas comes to the plant via a lateral from the Algonquin natural gas pipeline, but the facility can also burn distillate fuel (a.k.a. No. 2) when natural gas prices are high or supplies are unavailable. Its environmental permits limit oil burn to approximately 720 hours annually, but this flexibility is extremely important to the ISO-NE grid for reliability.

Photo from Exelon website available  via this link

Photo from Exelon website available via this link

In approximately the mid 1920s, the current site was developed by NStar predecessor company Boston Edison as the Edgar station. This was a coal fired unit supplemented with smaller oil fired turbines. Boston Edison retired the Edgar station sometime in the 1970s and the site was underutilized. In the mid-1990s, merchant generator Sithe Energies purchased the property when Boston Edison was obligated to divest its generating assets as part of electric industry restructuring.

Deregulation has been a long strange trip for many generating assets in ISO-NE and Fore River is no exception. Sithe Energies acquired the property from Boston Edison along with several other properties like the Mystic Generating Station in the late 1990s. It navigated the formidable Massachusetts permitting process and secured approval from the Energy Facilities Siting Board. You can review the final decision of the siting board here and it's an interesting read for several reasons, but one item that jumps out is the focus on CO2 emissions and discussions around mitigation strategies. In the photo below, you can see the plant as it exists today, with the oil tank, Rt. 3A to the North, and the power lines leaving the property to the south.

Aerial photograph taken from Google Earth on 2/4/14

Aerial photograph taken from Google Earth on 2/4/14

Sithe contracted with Raytheon's Engineering & Construction Group to build the plant, but midway through the project Raytheon sold this division to the Washington Group......who subsequently went bankrupt. Luckily, Sithe's contract required Raytheon to ensure project completion and Raytheon was obligated to finish construction which they did. Sithe Energies was purchased by Exelon and set up as a merchant generation subsidiary. Unfortunately, this Exelon subsidiary ran into serious financial problems in 2003 and Exelon handed the Fore River plant to its various creditors.

The creditors sold the Fore River plant to US Power Generation in 2005 who operated the facilities under the Boston Generating Co. subsidiary. The shale gas revolution wasn't kind to Boston Generating as they were heavily leveraged in a falling price environment and they were forced to declare bankruptcy in 2010. There are still some very angry creditors from this event. Google "Boston Generating Creditors" and you'll find plenty of info.

Constellation purchased the Fore River Generating station out of bankruptcy and Exelon merged with Constellation in 2011, reuniting the plant with its original owner.

This plant is a critical part of the ISO-NE electric grid and its dual fuel capabilities have been especially valuable during December 2013 and January 2014 when natural gas supplies have been scarce. One downside of the dual fuel capabilities of this facility is that distillate oil is delivered by barge to the tanks onsite, which requires the Fore River Bridge to open for extended periods of time. If you've ever had to sit through a bridge opening on 3A and deal with the resulting traffic, you know that it's no fun, but these bridge openings are the cost of fuel redundancy that gives us a reliable power grid. The MA Dept. of Transportation announces bridge openings on its Twitter feed at @MassDOT.

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.

Google Buys Nest Labs for $3.2B and Gets Back in the Energy Game

By now its old news that Google purchased Nest Labs for a very large sum,,,,in cash no less. This author purchased a Nest early on and has been greatly impressed by its learning capabilities (it knows what days I work from home). The real value in smart thermostats goes well beyond their adaptive learning capabilities, scheduling functionality, or optimization tools. These thermostats represent a grid level resource and are the first step towards a consumer facing smart grid.

For approximately the last 20 years, many utilities around the country have had residential and small commercial demand response programs that have relied on thermostats, electric hot water heaters, and other devices that can be cycled or interrupted by a radio signal sent by the utility. There are several companies that offer this service to utilities and some of the best known would be Honeywell and Comverge. For utilities, residential demand response represents a demand resource at the top of the dispatch stack and consumers typically decide to participate in order to receive a bill credit each month. These programs typically don't involve much consumer engagement and many consumers forget that they are participating in these programs. The graphic below, shown on the Bonneville Power Authority's webpage, illustrates residential demand response 1.0 very well.

Graphic from Bonneville Power Authority's Energy Efficiency webpage. Graphic links to BPA website.

Graphic from Bonneville Power Authority's Energy Efficiency webpage. Graphic links to BPA website.

Residential demand response 2.0 emerged in the deregulated Texas electricity market, known as the Electric Reliability Council of Texas (ERCOT), approximately three years ago. Deregulated electricity markets have become laboratories for consumer facing smart grid technology and ERCOT has led the way in many respects. Over the last three years, nearly every residential electricity customer in Texas has received a smart meter from their utility. The following Texas Investor Owned Utilities (IOUs) have deployed smart meters: AEP Texas; Oncor; Centerpoint; and Texas New Mexico Power. In addition, many of the Co-ops and municipal utilities in Texas have either deployed smart meters or have plans to do so. Smart meters are the first piece in the smart grid puzzle. The second is meter data management.

Each of the Texas IOUs banded together to create a single entity to manage the collection and storage of the vast amounts of data generated by smart meters. This entity is known as Smart Meter Texas and by combining resources, the Texas IOUs were able to create a robust platform for meter data management for all of ERCOT. Oftentimes, smart meter deployments do not live up to expectations due to the massive investment required to modernize utility Meter Data Management Systems (MDMS). When the MDMS isn't capable of handling the "Big Data" from smart meters, the data becomes trapped. We wrote a previous post about this. Each of the Texas IOUs, Smart Meter Texas, and ERCOT invested heavily to ensure that consumers could fully benefit from their smart meters from day one.

The third piece of the puzzle is a deregulated electricity market. In ERCOT, all customers are required to purchase electricity from a deregulated third party electricity supplier. These electricity suppliers must use the interval data that records the usage of their customers to purchase electricity in the ERCOT wholesale electricity market. An electricity supplier in ERCOT has to balance purchases with actual usage as recorded by the smart meters. This is unique to Texas and a handful of other jurisdictions. Most utilities in other deregulated electricity markets use what is known as a "profiled load" for market settlement of residential load and customer interval data isn't a part of the process....presuming its even available.

The ERCOT market can get crazy expensive during the summer months and wholesale prices are allowed to rise as high as $9,000 MWh (that's 9 bucks a kWh). Since deregulated electricity suppliers are fully exposed to these price spikes due to their need to purchase electricity according to the interval metered load of their customers, they have a large incentive to discourage their customers from using electricity during these high priced events. The graph below indicates the real time price of electricity in the ERCOT market on September 3rd, 2013. This wasn't a particularly hot day (by Texas standards), but a generator tripped offline in the late afternoon and the associated loss of supply was enough to make the market very tight. Prices spiked to $4,900/MWh during the interval ending at 5:45 PM. These types of fleeting price excursions are pretty common in the new ERCOT nodal market and they can be very hurtful to deregulated energy suppliers, especially the smaller ones. While this price spike didn't kill any of the smaller suppliers, several of these in a month or a spike lasting more than a few hours would be enough to cull many of the under-capitalized ERCOT market participants.

ERCOT Sept 3rd Price Spike.png

Deregulated electricity suppliers can't directly influence the wholesale cost of electricity and historically they haven't been able to influence the load patterns of their customers. Smart thermostats changed all of that and sophisticated electricity suppliers in ERCOT have been using thermostats to reduce the consumption of their customers during price spikes like the one shown above. Reliant, an NRG Subsidiary, made a big splash in 2012 when they began bundling Nest Thermostats with new fixed price electricity rate plans. Just Energy has a similar offering via their partnership with Ecobee. TXU offers a bundled thermostat rate plan in the Oncor service territory and Champion Energy Services is also getting into residential demand response. Smart thermostats are a valuable risk management tool for deregulated energy suppliers because they represent a physical hedge since they can reduce load rapidly and reduce exposure to price spikes. Bundling deregulated electricity supply with efficiency products is an emerging trend that is rapidly building momentum. Right now, the thermostats are a risk management tool for the suppliers as much as they are a consumer engagement strategy.

Back to the Google acquisition of Nest. These smart thermostats are the first commercially successful products in the coming "internet of things." The thermostat provides Google a window into your HVAC system, but also your lifestyle and sleep/wake patterns (marketers might like this info). In addition to learning about you, the smart thermostat will soon be able to talk to all the Zigbee enabled devices in your house (think dishwashers, clothes dryers, etc.) and direct a symphony of appliance activity based on energy prices. In the near future, your dishwasher will know to slow down or pause if there is a price spike in the ERCOT market. Nest also offers Google a great entry point into home security systems. The smart thermostat knows when you are home and it probably always knows when burglars break in when you are not home, especially if your mobile device tells the Nest that you are not home.

The home security angle is particularly interesting because the Honeywell line of Wifi thermostats were developed using the Honeywell security system platform. This author recently installed a Honeywell RTH6500WF thermostat for a friend and installed the Honeywell Total Connect Comfort app on multiple smart phones. Notice that when you click on the Total Connect Comfort link, it takes you to a login page on the website. Honeywell used its security system platform to move into smart thermostats (although Honeywell has long been king of conventional thermostats) and Google will likely use the Nest acquisition to develop a home security product.

Presuming the Nest acquisition gives a window into what Google is thinking regarding the future of the smart home and the internet of things, this author is very excited about what is to come. 

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.  

Lets Look at a JCP&L Residential Invoice

This author grew up in New Jersey and enjoys regular visits back to the homeland. When I'm home, I often ask friends and family to give me copies of their utility bills. In this post, we are going to dissect a bill from Jersey Central Power & Light (JCP&L).

The bill shown below is from the billing cycle that ran from May through June 2013. This is an interesting billing cycle because the summer rates for Rate RS (Residential Service) begin on June 1st. As a result, the billed usage must be apportioned between the summer and non-summer rates. The total usage for the billing cycle was 1,230 kWh and the billing cycle ran for 30 days (May 14 - Jun 12). This account is metered by a traditional electro-mechanical meter, so exact usage apportionment is impossible. Since 12 days (12/30 = 40%) of the billing cycle fell in June, 40% of the usage, or 492 kWh (1,230 * 40% = 492) is allocated to June and billed at the June rates.

The second red box highlights the supply charges on the bill. All four of the New Jersey Investor Owned Utilities (IOUs) refer to supply charges as Basic Generation Service or BGS. Since New Jersey is a deregulated state, consumers have the option to take electric service from either their utility or from a competitive electric supplier. Remember, in deregulated states the supply charges on the bill are driven by market forces and the cost of fuels used to generate electricity. All the NJ IOUs participate in a staggered auction process where the BGS supply charges on the current bill represent the average cost of electricity procured over the last three years. The BGS auction process leads to more stable costs. In the bill shown above, the consumer has elected to stay with JCP&L for supply and has not chosen a competitive electric supplier. 

If this customer or anyone else served by JCP&L was to evaluate an offer for competitive supply, they would need to calculate their Price to Compare (PTC). This can be done by summing the line item charges in the BGS section and dividing by the number of kWhs in the billing cycle to determine the $/kWh unit cost. For those who really want to do their due diligence, they could find JCP&L's currently effective rate tariff and look up Sheet 36 where the generation portion of BGS charges for the RS rate are detailed. In addition, the customer would need to calculate the transmission portion of BGS rates which are found by summing the transmission charge located in the RS rate (Tariff Sheet 3, BGS line 2) and the transmission portion of BGS rates detailed in Tariff Sheet 36A (requires summing ~ 9 charges). The BGS rate and transmission charges should be summed to determine the exact PTC in $/kWh. This number may not perfectly match the billed value on the JCP&L invoice because JCP&L employs a tracking mechanism called the BGS reconciliation charge (found at bottom of Tariff Sheet 36A) where over/under recoveries of actual supply costs are credited/debited to consumers on a lagging basis.

The distribution charges of JCP&L rate RS have some complexity in them as well. In June - Sept, there is a tiered rate system where usage over 600 kWhs is billed at a higher rate than the first 600 kWh. During Oct - May, all usage is billed at a flat rate. Tariff Sheet 4 includes several additional smaller charges that comprise the distribution portion of Rate RS. Although the Regional Greenhouse Gas Initiative (RGGI) Recovery Rider is not included in Tariff Sheet 4, it is incorporated by reference.

Many people look at their NJ electric bills and wonder where the sales tax is. Don't worry it's there. In NJ, the utilities and competitive energy suppliers are obligated to include 7% NJ Sales & Use Tax in their charges and not as a separate line item.

Above the charges included in the "Current Consumption Bill Charges" section are charge for a service called "PowerGuard." Note that there are four line items associated with this service and total charges add up to $7.10 (~$85/yr).  I was unfamiliar with this service, but found it on Tariff Sheets 52-53. PowerGuard is part of a legacy program by JCP&L called "Consumer Electronics Protection Service" where consumers can get surge suppression devices installed at the meter socket and at outlets. This rate has been closed to new entrants since 1999 and my presumption is that this customer has been paying these charges for at least 14 years without consideration as to whether this service or all of the associated devices are still needed. 

The JCP&L invoice, like all First Energy company invoices, includes a usage summary at the bottom left portion of the bill. This is a handy little graphic to help consumers and service providers understand annual usage patterns. A common complaint among many consumers deals with estimated meter reads. Reading electro-mechanical meters is expensive and JCP&L, like many other utilities, estimates approximately 4 readings per year to save on meter reading costs (e.g., labor, vehicle miles, etc.). The result can be invoices that do not match actual usage and are trued up in subsequent billing periods. The graph below shows the usage history as well as an A to designate Actual meter reads or an E to denote Estimated meter reads.

Hopefully you enjoyed this walk through a JCP&L bill and if your company needs rate and tariff expertise, please give us a call. We'd love to talk with you.


UPDATE - FEB 21, 2014 - After writing this blog post, I wrote JCP&L on behalf of this customer asking for them to be removed from Consumer Electronics Protection Service (see PowerGuard charges on bill). In the next billing cycle, the charges were discontinued. Although the customer offered to return all of the devices, surprisingly JCP&L did not want to receive 16 year old surge suppressors in the mail. 

Power Plant of the Week - Mount Tom

The Mount Tom coal fired power plant, located on the edge of Holyoke, MA is one of the few remaining members of a dying species here in New England. The plant has a capacity of approximately 146 MW, receives Northern Appalachian coal via rail, and draws water from the Connecticut River for both make-up water for the boiler and cooling water for the plant. You can see the plant very clearly on Google Maps and this author has gotten decent views of the plant from I-91 North in the wintertime when the leaves are off the trees. Most coal power plants in the U.S. receive their coal via rail and Mount Tom has fantastic rail access. There are several good websites maintained by New England railway buffs who track the movement of freight trains through the region and a little Googling will turn up many photos of loaded coal trains bound for Mount Tom.

This plant has a fairly interesting history. It was developed in the late 1950s by the Holyoke Water Power Company whose roots date back to late eighteenth century. It came online in 1960 and was converted to oil in 1970. Given subsequent historical events, the conversion to oil was not a good choice and the plant was converted back to coal in the early 1980s. The plant has retained modest dual fuel capabilities (coal & oil), although oil constitutes a small minority of the plant's annual fuel supply. Holyoke Water Power Company was acquired by Northeast Utilities (NYSE: NU) in 1967 and they operated the plant until 2006 when it was sold to First Light Power Resources. In 2008, global energy conglomerate GDF Suez purchased First Light and now they currently have the privilege of owning the Mount Tom plant.

Photo is from the  Action for a Healthy Holyoke  website

Photo is from the Action for a Healthy Holyoke website

The rapid changes in Northeast power markets associated with the discovery of shale gas and its extraction via fracking have not been kind to the Mount Tom plant. As recently as 2008, this plant was over 80% utilized and profitable. In the last three years, low cost natural gas has made the plant uneconomic the majority of the time and this is clearly shown in the graph below. Luckily for Mount Tom, the price of delivered spot natural gas to New England spikes during cold spells in winter and Mount Tom was called into service for a significant part of January and February 2013 and the same can be expected this winter. Mount Tom also sees occasional run hours during high priced periods in the summertime and any day where spot prices of natural gas exceeds about $8/MMBTU and ISO-NE demand is sufficient to warrant its dispatch.

Mount Tom Generation.png

As with all the other New England coal plants, Mount Tom has its share of vocal haters. Some of them, like the Conservation Law Foundation, have legitimate grievances such as repeated violations of the Clean Air Act. Others, just really hate coal a lot. Ironically, fracking has accomplished what activists have struggled to achieve for years as Mount Tom's days appears to be numbered due to economics. They submitted a delist bid for the ISO-NE 2016/2017 Forward Capacity Auction, but that doesn't mean the plant will be retired. It just won't receive capacity revenues and could still participate in the energy market on days when power prices are sufficiently high for it to be dispatched. GDF Suez installed new emissions control equipment in approximately 2010, but its unclear if these controls will satisfy MATs compliance after 2015. If not, then a shut down is a certainty, but otherwise Mount Tom could conceivably stick around as a predominantly wintertime generator for a few years after 2016. 

The State of Massachusetts has been proactive in working withe communities that will be affected by the impending closure of power plants including Holyoke. Mount Tom currently contributes approximately $600,000 annually to Holyoke via property taxes and supports about thirty high wage jobs. In a community like Holyoke, struggling to adapt to a post-industrial economy, a loss in property tax revenue of this magnitude is significant. 

Only time will tell when this plant shuts down, but Mount Tom is full of memories and within the decade this plant will join many other Mount Tom institutions that only exist in memories and historical archives. Many New England skiers may remember the Mount Tom ski area and associated summer water park which closed in late 1990s. Before that, there was the Mount Tom railway, which connected to the Holyoke streetcar system, and ascended Mount Tom to a grand house at the summit. This was a significant draw for tourism and was easily accessible to Northeastern city dwellers thanks to Holyoke's rail access. The Summit House(s) all burned down and today Mount Tom is divided into a publicly accessible State managed reservation area and various private property owners. 

My Utility Gave Me a Smart Meter, So Now What?

Many utilities across the U.S. and Canada have been deploying Advanced Metering Infrastructure (AMI) or "Smart Meters" over the last several years. The 2009 American Recovery and Reinvestment Act (ARRA), also known as the "stimulus" included funding for many Smart Meter projects via the Department of Energy. As a consumer, your ability to capitalize on a deployment of AMI by your utility depends on a variety of factors. In this blog post, we'll review some of these factors and discuss various AMI deployments.

Pennsylvania Power & Light (PPL) is a progressive utility in northeastern PA that led the way in AMI deployments in the U.S. In approximately 2002, PPL commenced the installation of hourly interval meters for all of its residential and small commercial customers. This hourly interval data is helpful for PPL (e.g., outage tracking, etc.), but it can also be used by competitive energy suppliers who can offer prices that reflect a customer's usage pattern. This is great for customers who use more energy on nights and weekends, but its bad for customers with poor load profiles whose true cost to serve would otherwise be socialized by flat rates. PPL's data also enables demand response and other innovative energy technologies to thrive in their service territory. PPL's communication technology is unique in that their meters send data back to PPL over PPL's powerlines.

The Electric Reliability Council of Texas (ERCOT) is currently on the leading edge of AMI integration into retail energy markets. In ERCOT, every consumer is forced to choose a Retail Energy Supplier (REP) and each REP must settle the hourly usage of their customers in the ERCOT market. The ERCOT market's maximum spot price is $9,000/MWh and a few hours of those prices are enough to blow up many REPs. As a result, the REPs have a significant incentive to help their customers conserve energy during high priced hours. The result is that small-scale demand response has become a retail energy product in ERCOT via bundling packages offered by REPs. For the REPs, this is a necessary risk management tool (DR as a physical hedge in their supply portfolio) and for the customer there are savings opportunities if they can shift usage away from peak periods with severe price spikes. Reliant (an NRG subsidiary) has partnered with Nest Labs to offer discounted supply in exchange for the ability to control the customer's thermostat. Champion Energy Services has recently begun to offer bundled DR options in its supply product offerings. Just Energy is one of the biggest residential DR companies in ERCOT, although there is little public evidence of it. Through their partnership with Ecobee, they've bundled energy supply with Ecobee thermostats and use them to manage residential air conditioning load during high priced intervals. The bundling of supply and DR in ERCOT is a great example of how smart meter data can unleash a wave of innovation that helps balance supply and demand and make an ERCOT capacity market totally unnecessary......., but I digress.

Smart Meter Graphic.png

In other parts of North America, the AMI picture is more mixed. Ontario made the installation of AMI a major policy objective and the majority of Ontario consumers now have "Smart Meters" and are subject to Time of Use (TOU) rates. The Ontario Energy Board has made peak demand reduction a cornerstone of its energy policy and AMI coupled with customer education around TOU rates has been a critical part of its strategy. Due to massive design flaws in the Ontario deregulated power market (we'll cover that in a future post), Ontario consumers get the majority of the TOU price signal through the distribution component of their bill. So far, it appears that the strategy is working as Navigant consulting recently released a study confirming a link between TOU rates, shifts in consumer energy consumption patterns, and a reduction in peak demands. 

The experiences of residential consumers in the Central Maine Power (CMP) service area in Maine are more typical of AMI deployments. CMP deployed Smart Meters after it was awarded a grant from the DOE as part of the "stimulus". The Smart Meters have been very helpful to CMP in that they have reduced the need for meter readers and associated vehicles/travel expenses and have also given CMP much better situational awareness regarding outages. CMP consumers have yet to reap the full benefits of this AMI deployment. While consumers can see their usage through the Energy Manager application, competitive energy suppliers and energy service providers can't obtain this information in a timely fashion for use in ISO-NE settlements (as they do in ERCOT). CMP needs to perform an overhaul of its Meter Data Management System (MDMS) before the AMI data is available fast enough for all participants in the retail energy value chain. Maine Public Utility Commission Docket 2013-00168 proceedings have indicated that the expense associated with a new MDMS and associated billing systems have far exceeded CMP's original projections. While the AMI roll out has reduced certain expenses, it has necessitated a significant capital expenditure requirement in order for the AMI and associated data to be fully utilized. At CMP, AMI and Smart Meters have been a journey with a destination to be reached sometime in the future.

In Massachusetts, the MA Dept. of Public Utilities just issued Order 12-76-A which lays out a framework for AMI investment and deployment among Massachusetts utilities. To date, NStar, NGrid, Unitil, and WMECO have engaged in "Smart Meter/Grid" pilots, but the technology has not been deployed on a significant scale. While many residential electric meters in MA may look smart, they are mostly one way meters that chirp reading data to meter readers who collect the data via drive-bys in specially outfitted vehicles with equipment that can collect the data. Order 12-76-A requires the utilities to develop 10-year Grid Modernization Plans (GMPs) and a Comprehensive Advanced Metering Plan (CAMP) to be submitted as part of the public record.  For a state with lots of technology, MA is taking its time in the development of AMI policy.

Although there are many pros and cons to AMI deployment, Smart Meters are seeing increasing resistance from people who are worried about the radiation associated with communications by these meters. In Massachusetts, there is a group called Halt Smart Meters - Massachusetts who have organized a vocal opposition even to pilots of the technology. While it may be easy to dismiss Smart Meter critics as modern day Luddites and scientific studies (such as the one conducted for Vermont Dept. of Public Service) indicate that the radiation emitted by Smart Meters is safe, there are people who claim to have electrosensitivity. Electrosensitivity is poorly understood and while many knowledgeable people assert that the symptoms are psychosomatic, its hard to say with 100% certainty that what people with claimed electrosensitivity are feeling isn't real. Opt-out fees, and even the ability to opt out itself, have been a major source of controversy in Smart Meter deployments and will likely continue to be until the issues around electrosensitivity are resolved (which could be decades). Other issues involve data security as hackers could use this data for criminal purposes (e.g., best time to break into your house) and data security is a constant and evolving challenge. 

Regardless of the issues, this author thinks Smart Meters are cool and if your firm needs help understanding AMI as it relates to retail energy markets/tariffs, give us a call.

That Contingency Bill Audit is NOT Free

At Energy Tariff Experts, we do a fair number of utility bill audits. Most of the time, we offer our services through energy brokers/consultants and efficiency firms, but sometimes we send proposals directly to the end user. We often find ourselves competing with contingency bill audit firms and have found that many end users do not understand the true cost associated with contingency bill audits where payment is based on a percentage of the "savings".

The vast majority of "savings" found through bill audits deal with sales taxes billed to exempt accounts. In deregulated markets where energy suppliers may change every few years, provision of the sales tax exemption paperwork is often overlooked during the contracting process. Turnover in accounting and procurement departments at end user firms is another cause of missed sales tax exemptions.

After sales taxes, utility or supplier billing errors are the next most common source of errors. Despite what some vendors may tell you, over 99% of utility bills are correct. Typically, utility bill errors are associated with certain triggers such as estimated meter reads, meter replacement, changes in meter multipliers, or changes to the IT in a utility's billing system. Any bill that is calculated manually (e.g., virtual net metering credits, special contacts, etc.) has a much higher probability of having an error. For competitive suppliers, there are similar flags such as contract renewals for many accounts and complex pass-through charges. We've observed that many contingency bill audit firms do not understand competitive energy market structures well enough to vet pass-through charges. 

There are often additional opportunities for savings that many bill audit firms miss entirely. Oftentimes an account where usage has changed significantly (either up or down) may be eligible for a rate change. This often requires a detailed review of historical billings, tariff rules and procedures, and data analysis. Some utilities will have a myriad of optional rates (think California IOUs) or rates with a baseline and real time prices to allow for economic demand response within the regulated utility tariff structure (e.g., Georgia Power). A highly thorough bill audit should analyze these opportunities if they exist.

Bill Audit Items.png

When it comes to recovering sales taxes paid in error, each state is different in terms of the sales tax recovery process. In some states, the "Vendor of Record" (e.g., utility or competitive supplier) will handle the interface with the taxing authorities if presented with the correct paperwork and documentation of refund due. Those are the easy states. In other states, the end user must fill out the forms required to claim a refund and and they must be signed by a corporate signatory. In addition, a predominant use study may have to be conducted or updated in order to justify the exemption percentage. In our experience, customer education and guidance through this process is critical and we feel that the end user must fully understand any document that they will sign and submit to taxing authorities.

Bill Audit Costs.png

Many end users struggle to understand what they will pay a contingency bill audit provider. They may be quoted a percentage of the "savings" (often 30-40%), but the methodology for calculating "savings" may be opaque (on purpose). In addition, "savings" can be defined as avoided spend over a period of up to two or three years. If there is a five or six figure sales tax recovery opportunity, the contingency bill audit will start to seem rather expensive. 

At Energy Tariff Experts, we do bill audits on a fixed fee basis or a discounted fee with a clearly defined bonus if certain straightforward targets are met. As an end user, if you think that you have billing issues, you probably do. We've had many experiences where we've delivered over six figures in recoveries or reduced future spend for clients where our fees have totaled only a few thousand dollars. The sales pitch for contingency bill audit firms tends to resonate with highly budget conscious consumers, but we'd advise anyone worried about a budget to spend some money upfront on a thorough audit with a detailed report/presentation as a deliverable instead of handing over a five or six figure payout to a contingency firm that found some low-hanging fruit. An educated consumer is a better consumer and the Energy Tariff Experts bill audit process is designed to ensure that the customer is fully educated on every step of the process and that all the savings end up where they belong, in the customer's pocket.

Time to Dust Off Your Dual Fuel Operational Procedures

Based on the events of the last two weeks, it looks like the Winter of 2013-2014 is going to be a wild ride in New England. You're probably tired of hearing this by now, but natural gas pipeline constraints coupled with an electric grid reliant on natural gas results in scarcity and high prices on the coldest days when space heating load and electric generators are competing for the same supplies. Last winter, there were several days where the spot price of natural gas exceeded the cost of Nos. 2 and 6 fuel oil and we discussed that in a prior blog post. For customers with dual fuel capabilities, it was actually more economic to burn oil than natural gas on many days and we expect that to be the case this winter as well. 

The graph below shows natural gas spot prices on several major pipelines serving the Northeast U.S. The most important feature in this graph is that all of the New England delivery points spiked in the last few days, while prices west of the Hudson River were much more subdued. This bifurcation of Northeastern gas markets is a recent development and is largely driven by the increase in gas supplies from the Marcellus which can reach the mid-Atlantic, New York, and southern Ontario, but just can't seem to get into New England in sufficient volumes.

Dec 13 gas spot rates.png

Fuel oil is a little different from natural gas in that the daily spot price matters less than the price you paid the day you filled your tank. As a result, its possible to have a static strike price for switching from gas to oil. As an interuptible gas customer, its possible that the utility will make the decision for you on certain tight days, but there will be other days that present an economic arbitrage opportunity even if the utility does not have to activate curtailments. The table below shows fuel oil prices at common delivery points/terminals as reported by the Oil Price Information Service (OPIS) on 12/6/2013. 

Oil Price Table.png

Although No. 6 Fuel Oil is getting rarer and rarer these days, it will likely be economic to burn many days this winter. The same will be true of No. 4 fuel oil. No. 2 fuel oil is pretty expensive and we've made some estimates to convert the quoted wholesale prices into retail prices in $/MMBTU. As a result, the actual delivered price to your tank will vary based on your fuel oil vendor, delivery size, and your specific location. Despite the price of No. 2, we estimate that there will be a few days this winter where natural gas spot prices in New England will exceed $30/MMBTU. If your natural gas supplier cashes you out daily (Sprague, Hess, Global, and Shell offer this), then you can cash in on your flexibility by reselling your Daily Contract Quantity (DCQ) at the prevailing spot price if you have a fixed price DCQ or just avoid high prices if you are on an index. You'll also do your gas supplier a huge favor as your dual fuel capabilities represent a physical hedge in their portfolio. In order for this to work, you'll need to ensure that you have frequent communications with your natural gas supplier as they would need to provide you with price data.

If you have dual fuel capabilities and need to review your utility's interuptible program or determine a strategy, call us. We've worked with dual fuel customers throughout the U.S.