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.

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. 

Power Plant of the Week - Schiller Station

The Schiller Station is owned by Public Service New Hampshire (PSNH) and is named after Avery Schiller, a dominant figure in PSNH management who helped shape the modern PSNH over a career spanning from 1924 through 1970. The plant is located in Portsmouth, NH along the Piscataqua River, just north of the I-95 bridge connecting Maine and New Hampshire. If you are able to take your eyes off the road, you can see the plant pretty clearly from the bridge. PSNH, a subsidiary of Northeast Utilities, is unique among New England investor owned utilities in that PSNH still owns generation that is part of the rate base. The Schiller Station is one of three major fossil fuel plants in the PSNH generating portfolio.

Currently, there are three active units (Units 4-6) at Schiller which were brought online in the early to mid 1950s. Units 4 & 6 have dual fuel capabilities (residual oil & low sulfur coal) and Unit 5 burns biomass. Unit 5 was retrofitted to burn wood chips, woody biomass, and wood waste products in the mid-2000s and entered service in late 2006. PSNH created a special entity for Unit 5 called Northern Wood Power and it appears that this venture has been an operational and financial success for PSNH and the local forest products industry.

Photo of Schiller Station. Photo Credit: PSNH obtained via Flicker

Photo of Schiller Station. Photo Credit: PSNH obtained via Flicker

The Schiller Station has seen its share of controversy lately as coal generation has become rather unpopular in New England. The Board of Selectmen of Elliot, ME voted in June 2013 to petition the U.S. Environmental Protection Agency (EPA) to conduct a detailed study of the plant's emissions. Elliot, ME is directly across the Piscataqua from Portsmouth, NH. The basis of Elliot, ME's request to EPA lies in Section 126 of the Clean Air Act, which allows for residents of a downwind state to request EPA involvement in review of emissions from a facility in an upwind state if the environmental regulators in the upwind state are perceived to be ineffectively dealing with emissions violations. The petition by Elliot, ME is focused on the potential of the Schiller Station to exceed the National Ambient Air Quality Standards (NAAQS) for Sulfur Dioxide (SOx) and does not rely on an actual dataset that proves a violation. The Sierra Club has been actively involved in the efforts of Elliot, ME.

Although the Schiller Station does have legacy pollution issues (like every old fossil fuel generator), it has been upgraded with modern pollution controls such as electrostatic precipitators (to remove particulates) and Selective Non-Catalytic Reduction controls to reduce Nitrogen Oxide (NOx) emissions. Although Schiller does not have controls for SOx, they manage SOx emissions by purchasing low sulfur coal. Buying low sulfur coal is a common compliance strategy for older coal plants in the U.S. Northeast as the added cost for low sulfur coal is typically much less than the cost to install SOx controls. Although Units 4 and 6 at the Schiller Station are currently compliant with EPA regulations, its unclear if they will be able to survive past the compliance deadline for the new Mercury and Air Toxics (MATs) standards that will take effect by 2015. 

Environmentalists often target the water intake and discharge permits of older fossil fuel plants and the Schiller Station is no exception. Although Schiller is in compliance with its National Pollution Discharge Elimination System (NPDES) permit issued by EPA under the Clean Water Act (CWA), the current permit dates from 1990. The CWA mandates that NPDES permits be updated every five years, but in practice this has proven to be unattainable and unrealistic for environmental regulators with limited resources. Once adequate permits and compliance limits are set for many facilities, the permits continue in perpetuity despite exceeding their statutory expiration. In 2012, the Sierra Club and "Our Children's Earth Foundation" sued the EPA to compel them to update the NPDES permit for the Schiller Station.

Despite all the recent bluster regarding pollution issues, actual emissions from Units 4 and 6 at Schiller have declined substantially over the last few years due to changes in the ISO-NE power market. These units can't pollute if they don't run and low natural gas prices have made coal/oil fired units like these uneconomic. The graphic below is taken from NH Public Utility Commission (NH PUC)  IR 13-020 which was an investigation and report on PSNH's ownership of generation assets. The graphic shows the utilization of various PSNH generating assets. Note how Schiller Units 4 & 6 continue to see their run hours reduced while Schiller Unit 5 (biomass) has consistently delivered capacity factors near 80%.

NH PUC IR 13-020, Report on Investigation into Market Conditions, Default Service Rate, Generation Ownership, and Impacts on Competitive Electricity Market. page 15

NH PUC IR 13-020, Report on Investigation into Market Conditions, Default Service Rate, Generation Ownership, and Impacts on Competitive Electricity Market. page 15

NH PUC IR 13-020 has some great data points regarding the Schiller Station. Due to the declining utilization of this plant, PSNH is does not have any active contracts for coal supply. They are taking delivery of delayed shipments associated with an expired contract and working down the coal pile at the site. The economics of Units 4 & 6 are currently highly challenged and these units are resulting in losses for PSNH. Unit 5, powered by biomass, is currently profitable and derives revenue from the sale of electricity, RECs, and Production Tax Credits (PTCs). The PTCs will expire in approximately 2017 and major changes to the biomass eligibility standards for the MA and CT Renewable Portfolio Standards may have an adverse effect on the REC income stream for Unit 5. Nonetheless, Unit 5 has been a financial success through the present time as evidenced by the valuation analysis in IR 13-020 and its capacity factor near 80%.

Schiller Station is similar to many older coal and oil fired generating assets in the U.S. Northeast. Although Units 4 and 6, are needed during extreme heat and peak winter temperature driven load spikes, they are dormant for much of the year. Given the ghastly economics of Units 4 & 6 in the current ISO-NE power market and the looming MATs compliance deadline, its unlikely that these units will be in operation at the end of this decade. Although environmentalists are attacking this plant on several fronts, economics will seal its fate and this may be hastened by the potential for NH PUC to order PSNH to divest its generation assets. At this point, its unclear in NH PUC will go that route, but if they do it will not bode well for continued operation of Units 4 & 6. Unit 5 will probably soldier on so long as it continues to remain profitable.

Power Plant of the Week - Bear Swamp Hydroelectric Power Station

While energy storage is a hot topic these days, the concept has been around for a very long time. Pumped storage hydroelectricity has been used commercially for many decades with numerous large scale installations throughout the U.S. The business model for pumped storage hydro is actually quite simple: pump water up a hill when prices are low; let water flow back downhill and spin turbines to generate electricity when prices are high. As long as the cost to pump the water uphill is less than the revenues generated when it flows back down, the business model is sound. There is a great wiki on pumped storage hydro that you can read here.

In the late 1960s, load growth in New England was robust and the New England Power Company, an affiliate of the New England Electric System (NEES) responsible for power plant construction and operation, needed to add peaking resources to the system. Construction of the Bear Swamp Hydroelectric Generating Station began in the late 1960s and concluded in 1974 when the project came online. The Bear Swamp plant is located along the Deerfield River in Rowe, MA, just below the VT - MA border. The Deerfield River is often referred to as the "hardest working river in New England" because of its many hydroelectric facilities. 

Bear Swamp has some really interesting operating characteristics. It can ramp from zero to full output (~585 MW) in three minutes and holds up to 3,000 MWhs of energy which can be discharged over a period of five hours. It takes approximately seven hours to recharge Bear Swamp by pumping water back up into the impoundment. Over the last several years, it has had a capacity factor of approximately 8% which is in line for a peaking resource. Its total annual output over the last four years has ranged from 350,000 to 450,000  MWhs and the amount of output is heavily influenced by the price spread between on and off peak hours.

Base map is from Google Maps - Satellite view

Base map is from Google Maps - Satellite view

The story of Bear Swamp is a familiar one in the ISO-NE power market. The plant was divested by NEES in the late 1990s as part of deregulation. It was purchased by USGen New England which was a subsidiary of National Energy & Gas Transmission (NEGT), which in turn was a subsidiary of Pacific Gas & Electric (PG&E). Thanks to Enron, PG&E had to declare bankruptcy in the spring of 2001 and its subsidiaries were forced into bankruptcy as well. If you click on the NEGT link above, you'll see that their website is still up and discusses the unwinding of the company. They also still have a page up showcasing Bear Swamp as one of their assets.

In the spring of 2005, Brookfield (then known as Brascan) and Emera purchased Bear Swamp and the Fife Brook Dam (a 10 MW run of the river hydro facility) for approximately $92 M. They have been operating the facility since and Emera's financial statements indicate that it is profitable. There is currently a long term PPA in place with the Long Island Power Authority (LIPA) for a portion of Bear Swamp's output. The LIPA PPA was enabled by the construction of the Cross Sound Cable.

Brookfield power has renamed Bear Swamp the "Jack Cockwell Station" in honor of Brookfield's chairman and former CEO Jack Cockwell, but the name hasn't really caught on yet. As far as we're concerned, its Bear Swamp, but Brookfield has uploaded some really great pictures of the facility on Flicker here and they refer to the facility by both names.

In summation, pumped storage hydro is a proven low carbon dispatchable peaking resource and places like Bear Swamp have been providing energy storage to the grid since before most current energy storage entrepreneurs were in grade school. Pumped storage hydro is proven and totally safe (unless you forget to shut off the pumps and overtop your dam) and Bear Swamp will continue to provide a peaking resource to the ISO-NE grid for many years to come.

Power Plant of the Week - Mars Hill Wind

Most recent PPotWs have been older fossil plants so we thought we'd shake it up a bit and profile a utility scale renewable generating asset. First Wind's Mars Hill Wind Farm is a great place to start. Its located in Aroostook County, Maine and was the first utility scale wind project constructed in New England. Mars Hill has 28 1.5 MW wind turbines with a nameplate generating capacity of 42 MW and is owned and operated by a First Wind subsidiary called Evergreen Wind Power, LLC. Emera, the Canadian utility that owns Bangor Hydro, is an equity partner in the project. It came online in March 2007 and has been reliably generating energy ever since.

Mars Hill wind turbines. Photo originally appeared on Xconomy.com

Mars Hill wind turbines. Photo originally appeared on Xconomy.com

First Wind is the company formally known as UPC Wind and they began initial work on the Mars Hill project in 2003. By 2005 they were ready to build, but the looming expiration of the wind Production Tax Credit (PTC) put the project on hold. The uneven lapses and renewals of the PTC have been a chronic problem in the wind industry for years and have created havoc and inefficiency throughout the wind supply chain. In the second half of 2005, President Bush signed EPACT 2005 and the PTC issue was resolved. In addition, First Wind had sorted out issues regarding the eligibility of the Mars Hill project for Class I Renewable Energy Credits (RECs) in CT and other New England states. 

The reason for the uncertainty in REC eligibility was due to the fact that Aroostook County, ME is not connected to the ISO-NE power grid. Its served by Maine Public Service (MPS), which is connected to the New Brunswick, Canada grid. The output from Mars Hill is connected to the MPS system via a 69 kV transmission line and primarily serves local native load. The REC issues were ultimately resolved and the project was constructed in 2006 and brought online in 2007. 

Although the Mars Hill project is largely considered a success, it has had its share of controversy. Wind developers and regulators are still learning how to assess, prevent, and mitigate noise and acoustic issues related to wind turbines. While newer designs tend to be quieter, the issue isn't going away. Here is a link to an article regarding the complaints of certain Mars Hill neighbors who claim that the noise from the turbines is having a negative impact on their properties and well-being. 

Although Mars Hill was first, several other wind developments quickly followed in ME and the region has several additional pending projects. ME's sparse population, good wind resources, REC markets in New England states, and proximity to load centers in ISO-NE make it a great place for wind development. You can keep in touch with First Wind via their Facebook page.

Power Plant of the Week - Norwalk Harbor

The Norwalk Harbor Generating Station is located just off Longshore Rd in Norwalk, CT. Its on a peninsula known as Manresa Island that juts out into Long Island Sound giving the plant terrific access to water and deliveries of oil via barge. This plant was built in phases with the first unit coming online in 1960 and the second in 1963. Both units have nameplate capacities of approximately 163 MW and consist of steam turbines fueled with No. 6 oil. 

Norwalk Harbor as seen from Long Island Sound.

Norwalk Harbor as seen from Long Island Sound.

Like almost all New England power plants, Norwalk Harbor was built by the local incumbent utility, Connecticut Light & Power (CL&P). In 1999, it was sold off to NRG during the electric industry restructuring. Things quickly turned sour for NRG and many of the other merchant generators during the early 2000s. The economics of the Norwalk Harbor plant were marginal at the time of the sale and NRG was sliding into bankruptcy by 2002 (they ultimately filed and re-organized in 2003). In the fall of 2001, NRG gave notice to CL&P and ISO-NE that they were considering mothballing this plant due to poor economics.

In the early 2000s, the closure of Norwalk Harbor was not a possibility due to severe reliability problems in the ISO-NE Southwestern Connecticut (SWCT) portion of the grid. The grid in this area was extremely unstable during hot summer days and Norwalk Harbor's capacity was badly needed to prevent blackouts. Despite this, Norwalk Harbor's economics at the time were not good and the hottest days of the summer, when the plant would be needed most, also have the poorest air quality. This issue presented an additional constraint for the plant as air emissions permits for older poorly controlled plants often limit allowable emissions on days when pollutants in the ambient air exceed certain thresholds. Ultimately, ISO-NE awarded Norwalk Harbor a "Reliability Must Run" (RMR) contract to ensure that its capacity would remain online. An RMR agreement is a type of cost of service agreement for plants that are required for reliability despite being uneconomic.

Norwalk Harbor continued to receive extra payments from ISO-NE via an RMR contract until 2010. By then, increased demand response, flat load growth, and the operation of the new Norwalk to Middletown 345 kV transmission line along with other transmission improvements negated the need to keep this plant in service via special RMR payments. Once the RMR contract expired, NRG kept the plant online, but drastically reduced staffing. NRG determined that the plant could eke out a subsistence existence via ISO-NE capacity payments and occasional run hours during days with high power prices. 

Effective June 2013, NRG decided to close the plant. June marks the start of a new ISO-NE capacity period and the capacity prices for the June 2013 through May 2014 period were insufficient to support Norwalk Harbor's fixed costs. Although its always a bit emotional to see a power plant get retired, this plant had been on borrowed time for years. But for the grace of RMR contracts it lived this long and with a heat rate of ~ 12,000+Btu/kWh fueled by No. 6, it was completely incapable of adapting to the new ISO-NE price environment.  In both 2011 and 2012 it had a capacity factor of less than 1% and last generated power during the cold snap in February 2013. 

Power Plant of the Week - Salem Harbor Generating Station

Its been a while since we've named a PPotW, but writing about the Salem Harbor Generating Station (Salem Harbor) took a lot longer than we thought it would. Its a complicated plant with a long history. Once upon a time New England Electric System (NEES), predecessor company to the current National Grid, constructed the Salem Harbor plant. Units 1 & 2 (short smokestack) were constructed in 1952 with nameplate capacities of approximately 82 MW each. Both generated power via steam turbines fueled with bituminous coal. Unit 3 came online in 1958, is a coal fired steam turbine, and has a nameplate capacity of 165 MW. Unit 4 was constructed in 1972 and is a residual fuel fired steam turbine with a nameplate capacity of approximately 475 MW. The large tanks used for residual fuel storage are easy to spot on the property and the large coal pile is also a distinctive landmark. 

Salem Harbor viewed from the air facing Northwest

Salem Harbor viewed from the air facing Northwest

During the restructuring of the electric industry in New England, this plant was sold to USGen New England which was a deregulated subsidiary of Pacific Gas & Electric Corp (PG&E). As most people remember, PG&E had some problems after the California energy crisis and the USGen subsidiary had to declare bankruptcy. Dominion Resources, a subsidiary of Dominion Corp, purchased the plant from USGen in 2005 and operated it until 2012 when it sold the plant to Footprint Power LLC. Footprint Power intends to operate the current plant until 2014 and then redevelop the property with a natural gas fired facility (more on this later).

Salem Harbor has been famous (or infamous) due to its environmental record. Although its never been conclusively documented (go to p. 26), many environmental groups have alleged that this plant is responsible for elevated rates of certain cancers in the towns of Salem, Marblehead and Beverly. In 2003 Mitt Romney called a press conference outside the plant to condemn its environmental record and vowed to use his powers to force it to shut down.  In many ways, the closure of this plant has become a cause celebre among the New England environmentalists. Due to the age of the plant and its poor economics, it hasn't been upgraded with modern pollution controls. The lack of investment in the plant has also lead to workplace accidents in the last decade that have been very serious. To limit emissions of sulfur dioxide, the plant burns a low sulfur coal imported from Columbia. 

Salem Harbor viewed from the air facing North-NorthWest

Salem Harbor viewed from the air facing North-NorthWest

Despite its age and pollution issues, this plant could not retire because it was needed for reliability. Salem is in the Northeastern Massachusetts (NEMA) zone of the Independent System Operator of New England (ISO-NE) grid which is capacity constrained. Dominion actually wanted to retire this plant in 2008 and submitted a de-list bid to ISO-NE, but its bid was rejected since the plant was required to ensure reliable electric service in the NEMA zone. Units 1 & 2 were allowed to retire in 2011, but Units 3 & 4 were required to run until 2014. ISO-NE uses a special contracting mechanism, called Reliability Must Run (RMR) to keep resources like Salem Harbor open when they are needed for reliability due to transmission constraints on the grid despite unfavorable economics. In 2012, Unit 3 had a capacity factor of approximately 12% (e.g., it ran for 12% of all hours in the year) and Unit 4 had a capacity factor of less than 1%. Although this plant has been on death's door for a while, the shale gas revolution (a.k.a. fracking) and the resultant drop in ISO-NE electricity prices driven by lower natural gas prices has made closure by 2014 a certainty. 

Although Units 3 & 4 are needed for reliability in NEMA through 2014, there are some major transmission upgrades taking place in the ISO-NE grid that should relieve the transmission bottlenecks on the North Shore. The Greater Boston Transmission Project, a multifaceted upgrade of the regional transmission infrastructure sponsored by National Grid and NStar's transmission affiliates, should create another 1,000 MW of deliverability to NEMA by 2018.  There is also a speculative project, known as the SeaLink, sponsored by New Hampshire Transmission LLC (subsidiary of NextEra Energy) , that would build a HVDC line from coastal New Hampshire to the North Shore although its just a proposal at this point.

In 2012, Dominion announced that it had sold Salem Harbor to Footprint Power. This stunned many market watchers as most people found it unlikely that anyone would want to buy Salem Harbor. Footprint Power has stated that they want to demolish the existing plant and construct a natural gas fired power plant that would go into service by 2016. The City of Salem enthusiastically backed Footprint Power as they are very concerned about losing the property tax revenue paid by the plant ($4.75M in 2010 per Final Environmental Impact Report p.17). 

Footprint power then made an enormous controversy by lobbying the Legislature to force National Grid to sign a 15-year Power Purchase Agreement (PPA) with their proposed natural gas plant to ensure that it could get financing. Although this attempt was rebuffed, Salem Rep. John Keenan, Chairman of the MA House Committee on Telecommunications and Energy, and State Sen. Joan Lovely were able to get language requiring that the MA DPU study the need for a long-term contract with the plant inserted into the ironically titled "An Act Relative to Competitively Priced Electricity in the Commonwealth" which was signed by Gov. Deval Patrick in August 2012. Unsurprisingly,  the New England Power Generators Association and other deregulated ISO-NE market participants were very irate over this legislative end-run around the marketplace.

Per the mandate of Section 40 of the Act referenced above, MA DPU opened Docket 12-77 to study the need for additional generation in NEMA and to determine if a long term PPA was warranted. This MA DPU docket was proceeding in parallel with the lead up to ISO-NE's Forward Capacity Auction (FCA) #7 which was to procure the necessary resources for the NEMA zone for the 2016/2017 delivery year. The ISO-NE FCA was designed to send a price signal to the marketplace to incent the build out of new generation capacity for future delivery. Many in the marketplace were skeptical of the ISO-NE FCA since all auctions to date (FCA #s 1-6) had cleared at the price floor due to oversupply in the market. ISO-NE broke up the FCA into zones to better isolate regional capacity issues such as those in NEMA. Footprint Power bid their proposed natural gas fired power plant into FCA #7 and their bid cleared the market. This is great for ISO-NE because it shows that the FCA process works to send a price signal. This is great for Footprint power as they were able to secure a capacity price of $14.99/kW/month for five years beginning June 2016 which should be sufficient for them to raise financing for their plant. This is great for consumers because the integrity of the ISO-NE marketplace was preserved and they won't be saddled with uneconomic cost burdens due to a legislatively mandated long term contract. MA DPU wrapped up Docket 12-77 in March 2013 with a very well reasoned conclusion. MA DPU highlighted all of the tools that ISO-NE has to mitigate a capacity shortfall and ensure reliability of the grid. In conclusion, MA DPU stated that "ordering local distribution companies to enter into long-term contracts under Section 40 would unnecessarily and unduly disrupt the wholesale marketplace and shift the risks associated with generation development from developers, who are best positioned to manage such risks, back to consumers." MA DPU hit the nail on the head, the profits and losses (lots of losses these days BTW) should be borne by the developers and asset owners, not the rate-paying consumers.

Air Conditioning and De-Industrialization = Peaky Summer Loads

Industrial load is great to have in a power system because it's generally steady 24x7 load that results in high utilization of power generating assets. This utilization is important because it spreads fixed costs out over a large number of kilowatt hours and therefore lowers the effective cost per kWh charged to consumers. Load factor is the best way to measure the relative "peakiness" of an individual or a system load. Load factor is simply the ratio between the peak load and the average load. over a time period. A load factor of 50% means that the peak load is double the average load. 

Electric grids throughout North America vary significantly in their load factors. Alberta has one of the highest load factors at near 82%. This is due to the significant industrial load associated with the oil and gas industry. New England has a much lower load factor and it has been declining in recent years. This is due to the one-two punch of de-industrialization and increased adoption of central air conditioning. Once upon a time, New England had a thriving industrial economy with many three shift factories and bustling mill complexes. As the New England region lost its industrial competitiveness to places in the Southern U.S. and overseas, the industrial load decreased as a percentage of the total load over the last 25 years. At the same time, central air conditioning systems became widespread during the 1980s and 1990s and resulted in a significant increase in weather driven summer load spikes in the ISO-NE grid. 

The graphic below is very telling. It shows how peak summer demands rose throughout the 1990s and early 2000s and have been stable since 2006. Although the summer seasonal load factor has fluctuated from year to year, the general trend is downward. This isn't the annual load factor, but measures the load factor in the period from June - September. When load factor is near 50%, there are a lot of peaking resources sitting idle, waiting for a hot day. 

 

Summer Load Factor Slide.jpg

If you look at winter peak demands in ISO-NE, you'll note that the winter peak has been stable over time. Before air conditioning, ISO-NE occasionally peaked during the winter. This was the case in 1992 and a was semi-regular occurrence before the 1990s.  You'll note that the winter load factor has also been stable and the long term trend seems to indicate a modest improvement. For this analysis, winter is defined as December through February.

Winter Load Factor Slide.jpg

The one thing that jumps out from this review is how much air conditioning has changed the dynamics of the ISO-NE power grid in the last 20 years. It has changed the cost structure of the grid, making it more expensive to operate due to the vast quantity of peaking resources that must be available to serve the summer peaks. There is a huge energy efficiency opportunity to reduce the load attributable to air conditioning and many smart people are working on this problem. Lets hope they are successful. 

ISO-NE Capacity Charges - The Hidden Demand Charge

In this post, we are going to focus on ISO-NE capacity charges. Most Regional Transmission Organizations (RTOs) have some type of capacity market, the exceptions being Alberta and Texas, who rely on what's called an energy only market structure. In deregulated electricity markets, there are two main products: electricity; and capacity. Capacity can be viewed as a call option on electricity where a peaking resource is paid just to be on standby in the event that it's needed. In a grid with peaky load characteristics, capacity markets are crucial to keeping the lights on during spikes in demand. The graphic below shows the daily peak demands for the ISO-NE system during the summer of 2012.

ISO-NE Summer 2012.png

In the graphic, you can see that excursions over 23,000 MW in demand are infrequent. Despite their infrequency, there must be enough capacity available to meet demand on hot days when the load spikes. Although the graph above just shows 2012, most ISO-NE summers in the last decade have exhibited load patterns that look just like this.

In capacity markets, if capacity resources get paid to provide capacity then someone else has to pay. As Milton Friedman said,  "There is no free lunch" and in capacity markets end use customers ultimately pay for the capacity required to serve their loads. Determining how much end use customers should pay and how to calculate it is a tricky task. PJM, ISO-NE, NYISO, California, and Ontario all allocate costs to load using different methodologies. Over the next few months, we'll walk through each, but ISO-NE is a good place to start since its a pretty straightforward system. In the graphic below, you can see a simple illustration of how monies are collected from load and distributed to capacity resources.

Capacity Markets.png

Any customer with an interval meter is assigned an Installed Capacity Tag (ICAP) based on their demand during the ISO-NE annual system peak hour. This is called the customer's coincident demand. There are some exceptions to this in New England for clients in Vermont and those served by municipal utilities. Ultimately, those customers pay for capacity too, but the costs are socialized by the utility. For residential and small commercial customers, the ICAP tag is developed based on a formula. The graphic below shows how the ICAP tag is determined for two interval metered customers. One customer is flexible and can drop their load when they think a system peak is likely. The other customer can't because they are inflexible.  

ICAP Tag Determination.png

Each customer will get an ICAP Tag based on their coincident peak with the ISO-NE system, but there is a lag between setting an ICAP tag and actually paying for it. The graphic below shows the schedule for ICAP tag assignment and cost allocation. 

ICAP Tag Schedule.png

For many end use customers buying energy competitively in New England, treating capacity charges as a "pass through" item in the contract could lead to a significant cost savings opportunity. Capacity prices are set during the ISO-NE Forward Capacity Market (FCM) auction, but they change slightly from month to month based on the reserve margin and other factors that determine ultimate charges to load. The graph below shows historical capacity charges in the ISO-NE market. 

Historical Capacity Charges.png

End use customers can take control of this charge by reducing their afternoon demands on the hottest days of the year or by working with an energy service company that warns customers when peak load hours are likely to occur so they can initiate demand response procedures. Presently, Constellation and EnerNOC both offer such services in ISO-NE although there are some significant differences in how they bill customers for the service. If you want to talk more about this stuff, give us a call.

Dude, Where is my ISO-NE Demand Response Check?

Once upon a time, ISO-NE Demand Response (DR) was nearly a gravy train. Back in the early 2000s, the state of Connecticut would practically buy you a back-up generator if you were in the Southwestern Connecticut (SWCT) load pocket. While it wasn't quite money for nothing, it was a really good deal and customers only had to respond to audits and the occasional (like once a year) DR event. While I may wax nostalgic in hindsight, ISO-NE had a severe capacity crunch in that era, especially in SWCT and Boston. DR met a very important social and business need and people were able to make money by helping out by being a DR resource.

When EnerNOC launched its IPO in 2007, ISO-NE accounted for 60% of the firm's revenues. This halcyon period for DR in ISO-NE spawned a revolution in energy management as ISO-NE clearly demonstrated that customer load could exhibit demand elasticity. ISO-NE was the first deregulated market to embrace third party demand response providers. and the companies that pioneered the New England market are now selling their solutions globally. In addition to EnerNOC, other firms such as CPower (now Constellation), Energy Curtailment Specialists, and Comverge thrived in the ISO-NE market during this period. When the ISO-NE Forward Capacity Market (FCM) made its debut in 2007, it added a layer of complexity to DR but it also validated DR as a dispatchable capacity resource.

Fast forward to the spring of 2013 and the ISO-NE DR landscape looks much different. Many of the players from several years ago have left the market or substantially pulled back. EnerNOC recently significantly reduced its position in the ISO-NE FCM as the market had become unprofitable for all but the largest customers or those with advanced automation. 

Why did this happen? If you really want to get into the weeds, read FERC's Order on ISO-NE's proposed tariff revisions in Docket ER12-1627-000 but I'll summarize below.

Must Offer Requirement - ISO-NE is going to force DR providers to always offer DR capacity into the Day Ahead and Real-Time energy markets on a 24x7 basis. In a portfolio of many customers, its extremely difficult to determine how much capacity is available from each resource on an hourly basis and even more difficult to determine an appropriate offer price. Most DR resources have high opportunity costs and don't want to be dispatched more than a few times per year. In addition, a DR provider could be subject to a market manipulation accusation if they only offered their capacity at high prices not connected to opportunity costs. The Must Offer Requirement is really bad for DR.

Onerous Data Requirements - The DR providers remaining in the ISO-NE market have invested in data infrastructure, but the challenges of gathering near-real time data from many sites, ensuring its integrity, and sending that data to ISO-NE is a very difficult task. ISO-NE imposed data requirements on DR providers that became onerous, yet the economics of the market didn't justify the labor effort or technology required to meet ISO-NE's data standards. In addition, when corrupted data accidently slips past your quality control filters and results in a FERC investigation and penalty, you think long and hard about whether continued participation in the market makes sense.

ISO-NE FCM Floor Price Goes Away in 2017 - In all of the FCM Auctions, there has been a price floor that has provided certainty regarding the minimum price for capacity. ISO-NE has been oversupplied for capacity, but the price floor has provided support for capacity payments and ensured DR's economic viability. In 2017 this price floor goes away and that is likely to significantly diminish demand response payment rates in most of ISO-NE where it will no longer be economic for many end users to participate.

I'm pretty sure that DR will thrive again in ISO-NE, but for the average commercial or industrial customer, DR will be on hiatus for a couple of years until these issues get worked out at ISO-NE. In the meantime, customers can manage their ICAP tags or participate in price response, but capacity based DR in ISO-NE is taking a break for now.

Northeast Utilities - Using the CT Legislature to Subsidize the Northern Pass

Here at Energy Tariff Experts (ETE), we are generally very supportive of energy deregulation. It allows for innovators, entrepreneurs, and non-utility companies to compete to build infrastructure and it shifts the economic risk for new generating and high voltage transmission infrastructure onto investors, where it belongs, and away from consumers.  When the Northern Pass was first proposed, we were very excited as it represented a major merchant transmission project in the ISO-NE grid.

Northern Pass Route Map posted on project website www.northernpass.us

Northern Pass Route Map posted on project website www.northernpass.us

First, a little background on transmission development. After deregulation took hold, a unique group of developers focused on privately funded transmission infrastructure evolved. These developers build what are known as merchant transmission projects. At a high level, there are two types of high voltage transmission projects: those that are reliability based; and those that are developed speculatively as merchant projects to alleviate inefficiencies in the grid. Reliability based projects can use eminent domain to secure a Right of Way (RoW) since they are needed for the public good (e.g., reliable power supply) whereas merchant projects do not have the option to use eminent domain and must come to commercial terms with each property owner in the RoW in order to secure easements to build or traverse.  The Northeast has seen numerous successful merchant transmission projects in the last decade including the following: The Cross Sound Cable; The Neptune Cable; the Linden VFT; and the Hudson Project. Note that all of these are mostly built underwater.

At ETE, we are supportive of merchant projects and do not have a position on any of the controversies around the siting issues associated with the Northern Pass.  What ETE does care about is that the rules of free and fair competition crucial to the functioning of a competitive deregulated market be adhered to. Currently, Northeast Utilities (NU) is attempting to use the Connecticut Legislature to mandate, via legislation (CT Senate Bill 1138), that CT consumers purchase the power from the Northern Pass under a long term contract. This is blatantly unfair to consumers and the investors and asset operators in ISO-NE who have played by the rules. NU is using its lobbying power and immense size to ensure that captive ratepayers in CT are used to subsidize this project via a long term contract at above market rates since the proposed legislation will re-classify conventional large hydro as "renewable" in the CT Renewable Portfolio Standard.

ETE firmly believes that if the Northern Pass is currently uneconomic, then it shouldn't get built until the economics of the power market justify it. In addition, it most certainly shouldn't get a subsidy as renewable energy since Hydro-Quebec does not need a subsidy for power they'd be delighted to sell us without a subsidy. In addition, claiming that Hydro-Quebec's conventional large hydro facilities should be given the same renewable energy subsidies offered to small scale wind, solar, etc. is absurd. While Hydro-Quebec's infrastructure represents major engineering accomplishments, many of their dams obliterated preexisting ecosystems and required the removal and resettlement of First Nations peoples.

Currently, the latest amendments to CT Senate Bill 1138 redefine large hydroelectric projects as Class I - eligible renewable resources. The specific language in the bill regarding large hydro is focused in Section 7 and Section 9d for those who care to read it. After a thorough read, its obvious that this language was written by NU lobbyists to enable the construction of the Northern Pass despite challenging economics. Lets hope that CT Legislators stand up for consumers and for the integrity of the ISO-NE power market and prevent this bill from becoming law. If NU wants to build the Northern Pass, they can do it with their own money.

New England's Wild Winter Power Market

Hi all,

This is a blog post I've been meaning to write for some time. New England is increasingly dependent on natural gas for power generation. This is unlikely to change anytime in the near future (good luck trying to build anything that isn't gas or renewables). In the last ten weeks, we've seen clearly that New England's heavy reliance on natural gas has a trade off which is extreme price volatility when physical natural gas supplies get tight due to high demand for natural gas from winter heating load on very cold days. 

Although there are five natural gas pipelines in New England, the Tennessee and Algonquin Pipelines are the most important due to the volume of gas they deliver to the region and due to the high quality pricing data associated with New England zones of each pipeline. Prices for Zone 6 of the Tennessee Pipeline and Algonquin City-Gates tend to be similar. The stunning increase in price volatility in daily physical spot natural gas prices is clearly shown in the graphic below. The winter of 2010-2011 was cold and snowy and spot prices flirted with $15/MMBTU in January 2011 (which I thought was high at the time). Each winter and summer since then we've had some transient price excursions to near ten bucks, but nothing all that worrisome from the perspective of the consumer. Then, around Thanksgiving 2012 things started to get crazy. 

Algon CGs.png

This graph is very important for power prices because the New England deregulated electricity market, administered by the Independent System Operator of New England (ISO-NE), uses a pricing system where the spot price for power is set by the cost of the last marginal unit of supply used to meet the last marginal unit of demand. As demand increases, higher cost units come online to meet the increasing demand. This is called merit order dispatch. Most natural gas power plants do not have firm delivery contracts for natural gas. They take what is known as interruptible service and are price takers for whatever the spot price of natural gas is on the pipeline that serves them. They bid into the ISO-NE marketplace based on the spot price of natural gas, the heat rate of the power plant (to be discussed in future blog posts), and whatever margin they require. When prices for spot natural gas go berserk, natural gas power plants offer into the market at prices that reflect the cost of their input fuel. Now that ISO-NE is heavily reliant on natural gas power generation, this causes power prices to come unglued as detailed in the graphic below.

Algon CGs and MA Hub Avg DA LMPs.png

The purple bars represent the Algonquin City Gates Mid-point spot natural gas price. The blue represents the average ISO-NE Day Ahead Locational Marginal Price (DA LMP) of electricity at the Mass Hub pricing node. The natural gas prices are shown on the axis on the right side of the graph. Up until the last three months, spot natural gas prices over $20/MMBTU were very rare. Now, they seem to be occurring weekly. I'm going to delve deeper into this topic in the coming weeks, but I bet there are a lot of energy consumers out there who can't wait until spring.