New England Dec 2013 Market Update

Things have certainly gotten interesting (or terrible) for energy consumers in New England over the last several weeks. All of the large New England electric utilities have released their default supply rates for the Dec '13 through Feb '14 period and the results are shocking to many. In short, the cost to serve load is well over $0.10/kWh for the months of January and February and we are seeing retail prices not seen in nearly six years. For consumers looking to renew competitive supply contracts or enter into additional hedges (e.g., layered block and index), the present time is not a good one. If you haven't locked or hedged yet, its really too late as the price environment for this winter is officially in crazy town. The graph below illustrates the default supply rates for larger customers in common New England electric utilities. 

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Of the energy brokers and marketers that we work with in ISO-NE, we're hearing that many are advising customers to stay on an index through March 2014 and just take the market price risk due to the massive premiums built into forward power prices. There are a few corners of New England where consumers taking utility default supply service will not be exposed to these prices. New Hampshire Electric Coop and PSNH still have managed power portfolios and their default prices are much more stable............(although above market outside of winter) and will not show such strong price increases over the winter.

Over the last three weeks, the physical ISO-NE Day Ahead and Real Time markets have exhibited significant price volatility which indicates that the forward ISO-NE power prices are directionally correct in that cold temperatures are producing high prices. The scatter plots below show ISO-NE Day Ahead prices in the NEMA zone over the last three weeks and also the last three days where cold weather has driven the highest prices of the season so far. Although we chose to graph NEMA prices, these trends are visible in each ISO-NE zone.

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In late November and early December, you'll note that there were occasional price excursions over $100/MWh and these typically occurred during the early evening peak which is typical for this time of year. The graph on the right shows the last three days where prices have really surged. This graph shows a phenomena witnessed last winter where the price separation between the peak and off-peak hours shrinks considerably during cold snaps. A close look at the graph shows that off-peak Day Ahead prices for Dec 11, 2013 are above $150/MWh. 

This is happening for two reasons. The first is that natural gas is the fuel on the margin in ISO-NE and all new generation builds in New England in the last 15 years have been either natural gas or renewables. The second is that winter heating gas demand is increasingly competing with natural gas fired electric generation for scarce natural gas supplies during peak winter conditions. This is not a new phenomena in ISO-NE, but its become more severe in the last two winters. The graph below shows ISO-NE forward power prices for delivery during the peak period (M-F 7am - 11pm) at the MASSHUB delivery point. The graph also shows prices for Basis Swaps for the Algonquin Pipeline City-Gates. Note that each price trend exhibits essentially the same pattern. Electricity prices are on the left axis and natural gas basis prices are on the right axis.

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In the graph above, you can see that prices were elevated in early Nov., but they really took off in the middle of November. January peak power at the ISO-NE MASSHUB is currently going for over $140/MWh. This is driven by the fact that January basis for the Algonquin City-Gates is over $13/MMBTU which represents 3X the price of the gas commodity at the Henry Hub.

If you are struggling with any of these issues and need help, give us a call. 

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.

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

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

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

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

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

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

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

Power Plant of the Week - Pilgrim Nuclear Generating Station

As we prepare to celebrate Thanksgiving, its a great time to think about the Pilgrim Nuclear Generating Station (Pilgrim) in Plymouth, MA. Its just a little ways southeast of Plymouth Rock in Plymouth Harbor, where the Pilgrims first set foot on the Massachusetts mainland. Pilgrim is owned by Entergy Corp (NYSE: ETR) which has owned and operated the plant since the late 1990s. It consists of one boiling water reactor with a nameplate capacity of approximately 680 MW. The story of Pilgrim is a familiar one in New England. The plant was constructed by the Boston Edison Company (NStar predecessor) and entered service in 1972. During deregulation, it was divested by NStar and acquired by Entergy.

Pilgrim as viewed from the south

Pilgrim as viewed from the south

During the late 1990s, Entergy acquired several nuclear plants throughout the northeast in states that were part of electric industry restructuring. Entergy's acquisitions were part of a trend during deregulation where merchant generators with deep expertise in nuclear operations took over nuclear plants that were formerly run by regulated utilities. The result, for most plants, was a significant increase in uptime, safety, and profitability under these new owners who specialized in nuclear plant operations. It was also important for the industry to have firms with significant financial resources running these plants due to their complexity, age, and the potential for costly repairs that could overwhelm a smaller utility owner. 

Nuclear plants are well suited to providing baseload power as they are either on or off with limited ability to run at partial capacity. The graphs below show the capacity factor of the Pilgrim plant over the last several years and a close up view of performance over the last 12 months. You'll note that Pilgrim has been a reliable resource to the ISO-NE grid with very high availability since the mid-2000s. The periodic dips in capacity factor are generally associated with refueling outages. The spring of 2013 was a bit of an outlier as equipment issues forced the plant offline for several weeks. 

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Pilgrim has been in the news a lot over the last two years since it has been in the process of renewing its license to operate which is granted by the Nuclear Regulatory Commission. The majority of the U.S. nuclear fleet is undergoing re-licensing since most plants were built between the late 1960s and mid 1980s. As these plants reach the end of their initial operating licenses, they must undergo a rigorous process for relicensure in order to stay operational. Invariably, the relicensing process provides an opportunity for supporters and opponents of nuclear power to engage in a heated public debate. Pilgrim, like most nuclear plants, has some very vocal opponents including Pilgrim Watch and the Cape Downwinders

Pilgrim's safety record has been good and the NRC is a strong regulator, but despite this, there will always be people who fear nuclear power. Accidents at poorly run facilities such as Fukushima don't help the image of the industry and geographical bottlenecks can cause anxiety among people who fear a nuclear incident. Some concerns of nuclear opponents are legitimate and one such concern is nuclear waste from spent fuel rods. The politics and paralysis around the Yucca Mountain long term storage facility has forced nuclear plants throughout the US to devise on-site storage solutions. Pilgrim is no different and is currently in the process of moving spent fuel rods into dry cask storage on-site. The embedded slideshow below provides additional information on dry cask storage at Pilgrim.

Another valid issue raised by nuclear plant opponents is thermal pollution and the damage to aquatic species caused by once-through cooling. Many older fossil plants also use once through cooling. The environmental impact statement required under NEPA as part of the Pilgrim re-licensing process illustrates the impacts of the cooling system to aquatic species. Specifically, aquatic species get trapped on the intake to the plant and are unable to escape due to the flow velocity. Also, some species are impacted by abnormal thermal gradients near the outflow as waste heat is discharged. During the summer of 2013, nature retaliated as the waters in Cape Cod Bay became unusually high and Pilgrim was forced to reduce output since the intake cooling water temperature exceeded specifications. The graphic below illustrates the intake and discharge locations for cooling water at the plant. Note that the intake is located within the protected embayment while the discharge sends water directly out into Massachusetts Bay.

Fig. 2-3 from Pilgrim EIS

Fig. 2-3 from Pilgrim EIS

Nuclear power plants tend to have very high staffing levels compared with fossil fuel plants. As a result, the impact on local employment is significant. Pilgrim employs over 600 people and there are many related jobs among subcontractors and other service personnel. Workers at Pilgrim are represented by the Utility Workers Union of America, Local 369. The presence of a highly professional union provides another check and balance against attempts to cut corners in the operation of a nuclear plant. Pilgrim is also a substantial contributor to the tax base of Plymouth, MA and currently contributes approximately $10M annually to the town government through a payment in lieu of taxes.

Although some of the issues raised by Pilgrim opponents are valid, Energy Tariff Experts poses the following questions:

Q: What would happen to ISO-NE  power prices if Pilgrim closed? 
A: They'd go up a lot.

Q: How can we transition to a reliable, reasonably priced, low carbon electric grid in America w/o nuclear as part of the mix?
A: We can't, if you want low carbon you need nuclear for baseload.

Q: Why can't we build new nuclear in America?
A: Absent financing issues in the merchant generation space, we don't know because the new reactor designs are much safer than the current operating fleet and for those concerned about safety, new nuclear builds would be a good thing.

In summary, as we celebrate Thanksgiving in 2013, we should celebrate the reliable performance of Pilgrim and its contribution to the ISO-NE electric grid and the regional economy.

Electric Thermal Storage Heat - The Hottest Thing in Maine

When most of us think of electric heat, images of 1960s/70s style buildings with baseboard heaters come to mind. This author lived in one such apartment building in Ithaca, NY where the wall-to-wall carpet matched the baseboard heaters (I don't miss either). In regions without natural gas service, electric heat is seeing a resurgence. Despite naysayers, it really is different this time because modern electric heat technology is vastly improved over the lowly baseboard heaters from years ago. Electric Thermal Storage (ETS) heat is a highly efficient controllable load that can store heat when power prices are low and discharge it during peak hours. This makes ETS heat a valuable resource to grid operators and utilities looking to dynamically balance supply and demand and access a low cost energy storage solution. The advantage to the homeowner is that an ETS heating system can store heat when prices are low (e.g., 2 a.m.) and discharge it later in the day when prices are high (e.g., 5 p.m.), resulting in a lower cost home heating solution compared to oil, propane, or traditional electric baseboard heat.

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There are two types of ETS heating systems. Hydronic systems work by heating a reservoir of water contained in a pressurized tank, typically during off-peak periods. Water has a high heat capacity and if the water tank in the system is sized properly, it will be able to store enough thermal energy to heat a home for many hours without drawing electricity. Some hydronic systems can heat a home for greater than 24 hours without requiring additional electricity. Hydronic ETS systems can be retrofitted onto existing forced hot water, forced hot air, or radiant heating systems. In addition, they can also serve as a supplement to a heat pump system. The other type of ETS heating system consists of ceramic bricks that can be heated to a few hundred degrees Celsius. These bricks are part of a heater module that can be charged up at night (with heat) and discharge heat throughout the day to keep a room warm. One advantage of a Ceramic ETS system is that units can be sized for whatever space they need to heat and they can be a direct replacement for electric baseboards or a supplement for a wood/pellet stove. The graphic above illustrates how a Ceramic ETS system works. The ceramic bricks are shown in red, the circuit board to the right controls the unit (so it only charges during off-peak/low priced times) and the fan at the bottom right pulls air over the bricks and out a vent to supply heat to a room. Dimplex  is a major manufacturer of ceramic ETS heating systems in North America and SmartBricks is a trade name for ceramic ETS systems installed and managed by a Rhode Island company called VChargeVCharge (which resells upgraded Dimplex heaters as well as retrofits for older systems) communicates with its heaters via the Internet to execute energy purchasing strategies that factor in weather reports, grid conditions, and wholesale electricity prices.

Central Maine Power (CMP) recognizes the benefits of ETS heat and they've developed a generous incentive program to encourage its adoption. They have a dedicated webpage for their ETS heat program and will offer a rebate of up to $4,500 for the installation of qualified systems. Many CMP customers, like other residents of Northern New England, do not have access to natural gas and heat their homes using No. 2 fuel oil, propane, or wood. In recent years, the costs of No. 2 fuel oil have risen significantly and heating with oil represents a financial hardship for many Mainers. Propane is also very expensive.

For ETS heat to deliver maximum value to the consumer, its important to have a Time of Use (TOU) rate schedule where electricity is less expensive during off-peak periods (e.g., nights & weekends). CMP offers several residential TOU rates for consumers with ETS heat or those who are energy conscious and willing to shift their consumption to off-peak periods to save money. Currently, CMP offers the following TOU residential rates which are viewable here on the CMP website: Load Management Service; Residential TOU; and Residential Optional TOU. The Load Management and Option TOU rates have subrates within them that customers can pick based on their usage patterns and circumstances. Most people can't bring themselves to read rate tariff schedules in their entirety, but each rate is summarized graphically below and compared to the standard CMP A-1 residential rate which is the default for any consumer who does not choose a TOU rate.

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Res TOU.png
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Generally speaking, the Residential Optional TOU Super Saver rate tends to be the least cost rate choice for ETS heat, although the other listed rates could also be viable depending on the consumption patterns of the house (e.g., occupancy and appliance run schedules). A modern ETS heat system, controlled via the embedded circuit-board will draw electricity during the green (off-peak periods) which is how these systems deliver their cost savings.

In rural Maine, ETS heat systems are competing with No. 2 fuel oil, propane, and wood/biomass. Although electricity powered air source heat pumps are also an option, performance issues in extremely cold temperatures have hindered their adoption in Northern New England. The table below summarizes the various types of fuels, approximate fuel costs, common conversion efficiencies, fuel costs in $/MMBTU of aggregate and usable thermal energy, and the estimated annual cost to heat a typical residential home in Maine. The table shows that ETS heat, while more expensive than natural gas and wood/pellets, has a clear cost advantage over No. 2 fuel oil, propane, kerosene, and conventional electric heat. 

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For Mainers with oil or propane boilers/furnaces near the end of their useful life, ETS heat should definitely be considered if they are CMP customers. For any consumer looking to replace electric baseboard heat or central heating, VCharge hydronic or ceramic ETS systems are a no-brainer and could offer a simple payback of less than two years. The ISO-NE power grid is getting cleaner each year and with all the new wind in Maine, ETS heat systems will be helpful to consume excess wind energy produced during the overnight hours and reduce the high energy costs for home heating in rural Maine.

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.

The Great Northern New England CNG Race

Large energy consumers in Northern New England have had it rough for the last few years. Natural gas prices have fallen drastically, but most of the region is cut off from natural gas pipeline infrastructure. Fuel oil and propane are the dominant fuels in this region, but both are very expensive on a $/MMBTU basis relative to natural gas. Although biomass can represent a low cost fuel option, burning biomass isn't for everyone. The result has been a major cost disadvantage for large energy consumers in large parts of Maine, Vermont, and New Hampshire. relative to their peers in the rest of the Northeast. 

In the last two years, several entrepreneurial companies have emerged to address the energy challenges faced by the consumers mentioned above. They are NG Advantage and Xpress Natural Gas (XNG) and they deliver Compressed Natural Gas (CNG) via truck to the customer's property. The truck trailer has a tank that can hold approximately 350 MMBTU of CNG and the trailers are designed to be left on the customer's property while the CNG is being consumed. This relieves the customer of the need to install their own storage tank and when the CNG in the trailer is depleted, it is replaced with a full one. For a customer to switch, they only need to install burners capable of burning natural gas and the plumbing required to connect to the CNG trailer. Hexagon Lincoln's TITAN tanks are currently very popular for trailer mounted CNG delivery systems and there is a major backlog of orders for tanks and trailers due to the growth of the CNG business.

In addition to XNG and NG Advantage, Irving Oil and Global Partners have also entered the CNG business. Irving Oil is delivering CNG to customers in Eastern Maine from its CNG facility in New Brunswick. Global Partners LP has partnered with OsComp and Bangor Natural Gas to build a CNG compression station in Bangor, ME. This station is currently under construction and should be online in a few months. XNG opened its Baileyville, ME CNG compressor station in early 2013 and is planning to construct another one in Augusta, ME in partnership with Maine Natural Gas. NG Advantage's CNG facility in Milton, VT taps the natural gas lines that run from the Quebec border down to Burlington, VT. This part of Vermont is served by an extension of the Quebec Gaz Metro system. NG Advantage is currently planning to build another CNG facility in Pembroke, NH in partnership with Clean Energy Fuels. The Pembroke, NH CNG station could be online by spring 2014. The map below details the locations, current and planned, of CNG compression facilities serving New England.

 

Base map from SNL Energy. Interstate natural gas pipelines shown in green. CNG compression facility locations are approximate.

Base map from SNL Energy. Interstate natural gas pipelines shown in green. CNG compression facility locations are approximate.

Although CNG is less expensive than No. 2 fuel oil and propane, there are many costs that are unique to CNG. Delivering CNG requires a diesel fueled semi truck. If we presume that the average semi-truck gets approximately six miles per gallon and diesel costs roughly $3.75/gallon, then each mile of transport costs $0.625 in diesel fuel. The miles of transport required are actually double the distance between the customer and the CNG compression facility because the empty trailers must be transported back for refill after a full one has been delivered. In addition, to diesel fuel, wages for truck drivers and vehicle maintenance impact the per mile costs. At distances greater than 150 miles from the CNG compression facility, the economics of CNG are challenged as transportation costs start to climb well north of $1/MMBTU. 

The other challenge facing CNG providers is cost volatility during the peak winter season. Each CNG provider is offering customers a fixed price per MMBTU (at least to our knowledge), but the wholesale cost of natural gas in New England during winter can swing wildly (see our previous post on that). Generally speaking, wholesale natural gas prices on the Maine and Maritimes pipeline will trade at a premium to Tennessee Zone 6 Dracut during cold weather. On very cold days, the CNG providers will potentially have exposure to spot natural gas prices that are higher than the contracted prices with their customers. Also, its unclear where the CNG providers stand if supplies become tight and the pipeline issues an Operational Flow Order (OFO) where certain users are restricted in their ability take natural gas. Each CNG provider has a risk management strategy in place, but the risk of tight supplies and elevated winter basis costs can't be totally controlled through hedging. This applies to the Merrimack valley lateral of the Tennessee pipeline as well. Customers who use natural gas on a year round basis are most attractive to the CNG providers as they can spread out the costs of supply during peak winter days over the entire year. For purely heating loads, we imagine the economics may be riskier if there is a very cold winter with multiple cold snaps.

NG Advantage's Milton, VT CNG facility is somewhat shielded from these issues since its natural gas supply comes from Canada. Ontario and Quebec do not have the severe basis risk and pipeline bottlenecks affecting the rest of New England so their wholesale supply costs will be less volatile. They are building a new facility in Pembroke, NH and this facility will face the same supply cost issues during peak winter as their competitors. Despite this, it will give them geographic proximity to the NH market where there is a lot of opportunity for CNG.

CNG is also creating some very innovative changes to the natural gas utility industry. Maine is unique in that natural gas utilities do not have exclusive franchise rights so getting service to new customers is critical for a utility like Maine Natural Gas who is competing with Summit Natural Gas of Maine for new service areas.  This article describes how XNG is helping Maine Natural Gas build  a "rolling pipeline" where CNG can supply a new local natural gas system that has not yet been connected to the larger Maine Natural Gas system. This partnership allows them to acquire and serve customers and build a market much faster than if they had to wait until all of their infrastructure was ready.

CNG is poised for explosive growth in Northern New England.................so long as natural gas stays cheaper than fuel oil or propane. We think it will in the near term, but the future is anyone's guess. 

If your facility is considering switching to CNG and you'd like some assistance evaluating your options, call us. We can probably help. 

Default Gas Supply Rate Trends for New England Utilities

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

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

 

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

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

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

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

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

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

Current Wholesale Price Data for NYISO and ISO-NE

Although we spend our days here at ETE swimming in price data, the current ISO-NE and NYISO future wholesale power prices seem worthy of a blog post. Although each grid is divided up into zones, the most common price benchmarks are the MA Hub and Zone J for ISO-NE and NYISO, respectively. Over the last year, the futures curve for both markets has ranged from flat to backwardated. (Note: Backwardation is a term used when commodities for future delivery are less expensive than in the near term). Although NYISO only flirted with backwardation briefly, ISO-NE saw strong backwardation driven by expectations that many of the natural gas bottlenecks impeding deliverability to the region will be relieved by 2015/2016. This backwardation was significantly reduced on 8/28/2013 when Entergy announced the impending 2014 closure of Vermont Yankee.

Calculated per NYMEX OTC Data, symbols NYMEX.NI (On-peak) and NYMEX.H2 (Off-peak)

Calculated per NYMEX OTC Data, symbols NYMEX.NI (On-peak) and NYMEX.H2 (Off-peak)

The graph to the right shows the 30-day price history of an Around the Clock (ATC)  5MW block of power delivered to the MA Hub throughout a given calendar year. You'll note that 2014 was trading at a premium versus the out years until the Entergy VT Yankee announcement. Subsequent to the announcement, prices for 2015 jumped to parity with 2014 and prices for 2016 delivery rose, but not enough to erase the backwardation. Although Vermont Yankee is a small nuclear power plant, it is a significant source of baseload generation in Western New England and its loss may create additional congestion in this region of the ISO-NE grid in addition to raising prices for ISO-NE as a whole. Although its doubtful that Indian Point in NYISO will be forced to shut down pre-maturely, we shudder to think what might happen to NYISO Zone J future power prices if Indian Point goes away.

The table below shows data for ISO-NE and NYISO power prices presented in the form of a stock table. You'll note that the 52-week highs and lows are much tighter for NYISO than for ISO-NE. Also, while NYISO's current prices aren't much different from the 30 and 90 day moving averages, you'll note that ISO-NE prices have upward momentum right now.

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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.

Renewable Energy Costs Money Folks

In early August, Commonwealth Magazine published a short article regarding the costs of renewable energy mandates in Massachusetts (MA). You can read the article at this link. In essence, the article stated that the MA Renewable Portfolio Standard (RPS) and other related policies are causing increases in the monthly electricity bills of residential electric ratepayers. Although the article was very general in its numbers and assumptions, the basic premise was correct. The reaction to this article by local renewable energy activists was one of rage and hysteria and it resulted in National Grid issuing a clarifying statement to the article in which they apologized for telling the truth in their quotes to Commonwealth Magazine. 

The current MA RPS mandates a rapid build-out of renewable electric generating infrastructure in MA, the ISO-NE electric grid, and adjacent control areas. This build-out requires significant capital spending. In any electricity market environment (cost of service vs. deregulated), new infrastructure build-outs increase prices to consumers. Many regulated cost of service utilities in the US West and South have surcharges and riders on customers bills to pay for new fossil power plants currently under construction. The utilities allocate these charges to customers because the capital to fund plant construction has to come from somewhere. In deregulated market environments, investors (not ratepayers) assume the risk in investing capital to build new infrastructure. This is generally seen as beneficial for ratepayers since investors, not ratepayers, are the ones responsible for cost overruns and mishaps. In the MA deregulated energy market, renewable energy infrastructure investors recover their capital investment through sales of commodity electricity and Renewable Energy Credits (RECs). Although the fuel for renewable energy generating infrastructure is free (e.g., solar, wind), they still require large capital investments to build. 

When MA deregulated its electric market in the late 90s, part of the deal was to create the RPS which was designed to serve as a funding mechanism for renewable energy infrastructure build out. The RPS has been subsequently expanded and modified over the years, but it essentially mandates that all energy suppliers obtain a certain percentage of their energy supply from an increasing amount of renewable energy each year. Municipal utilities are exempt from the RPS. The table below provides a breakdown of the 2013 RPS mandate. Below, we list the types of renewable energy resources that fall into each class. You can learn more about the MA RPS at DSIRE.org, the MA DOER website, or read one of the MA DOER RPS Summary Reports from prior compliance years.

MA RPS.png

Class 1 - solar PV; wind; ocean thermal or hydrokinetic energy; fuel cells utilizing renewable fuels; landfill gas; low-impact hydroelectric; advanced biomass; combustion of select energy crops like algae or biogas; and geothermal.

Solar Carve-Out - Special carve-out within the Class I mandate specifically for solar PV built after 2008.

Class 2 - mostly the same stuff as Class I, but from pre-1997 facilities

Class 2 WTE - Electricity generated from the combustion of municipal solid waste.

Alternative Energy Portfolio Standard - combined heat and power (CHP); Carbon Capture and Sequestration (CCS); flywheel energy storage, paper-derived fuel sources, and energy efficient steam technology.

Calculating the cost to load (a.k.a. ratepayers) associated with the MA RPS is actually pretty straightforward. Power supply provided to the consumer will be based off of ISO-NE market prices for commodity supply. The table above indicates the relative percentage of RECs (as a percentage of total load) that must be acquired to ensure compliance with the MA RPS. REC prices are quoted through brokers and are easily obtainable for those in the industry. Additional charges associated with MA renewable energy and energy efficiency programs that are billed on the distribution portion of the utility invoice can be found in the utility tariffs and/or rate case proceedings on file with the MA DPU.

The table below provides an approximation of the additional costs, on a $/kWh basis, to a typical small commercial MA consumer served by NGrid to pay for the MA RPS and associated renewable, alternative energy, and efficiency policies. The total cost per kilowatt hour (kWh) is approximately 1.5 cents and this cost is likely to increase in the near term due to the accelerating RPS requirements. For a consumer using 1,000 kWhs per month, this translates to an additional monthly charge of $15 (1.5 cents per kWh x 1,000 kWhs = $15). In the NGrid service area, the additional charges for residential consumers are slightly higher on a unit cost basis ($/kWh) due to a higher value in the "Energy Efficiency Charge" line item applied to residential billings. For reference purposes, a residential apartment averages 500/kWh/month, a suburban house averages 1,000 kWhs/month, and a small retail store might average 2,500 kWh/month. Other MA utilities such as NStar, Unitil, and WMECO will have similar costs associated with these programs. Municipal utilities are exempt from most of these cost mandates, except for the Regional Greenhouse Gas Initiative (RGGI), but they may have their own efficiency or renewable energy programs with costs recovered from consumers.

MA RPS 2-3.png

The problem as ETE sees it isn't the costs associated with renewable/efficiency policies, it's the way the costs of these policies have been communicated to the public.  Politicians everywhere have told the public that renewable energy lowers utility costs to all consumers. Unfortunately statements to that effect are completely untrue at the present time (although we think that will change). Climate change is a real problem with major associated societal costs. Fossil fuel power plants, especially coal-fired, have serious externalities and social costs that are not factored into the cost of their energy output. Voters have elected politicians in MA and other states who have promised a policy response to climate change. RGGI, the RPS, and the various energy efficiency programs are a logical policy response to climate change and reflect the will of consumers and voters. When Gov. Patrick ran for office, he pledged a major commitment to building renewable energy infrastructure. Once elected, he did exactly what he promised and created some very aggressive policies to advance renewables and energy efficiency.

These policies aren't free and consumers need to understand that a better energy future costs money. At ETE, we believe that renewable energy makes a lot of sense and energy efficiency is always a good investment. The current policy regime is what consumers and voters say they want and dealing with climate change now is probably less expensive than dealing with it later.

ERCOT 4CP - July 2013 Review

July 2013 was a strange one for ERCOT. Typically July is when things really heat up and the ERCOT grid gets very tight and expensive. As we discussed in a previous post, preliminary data indicate that the June ERCOT peak of 64,543 occurred on the 27th during the 16:45 interval. The July ERCOT peak of 64,968 occurred on the 31st during the 16:45 interval. The graph below shows maximum daily ERCOT system loads. The unusual feature in this graph is the low loads during the first and third weeks of July. Texas experienced a cooler and wetter than normal week during the third week of July and this is reflected clearly in the electric loads. Texas needs the rain given the current drought conditions, but it certainly made for an outlier in the load graph.

For customers working to manage their 4CP tag, we are halfway through the season. Calling the peak in September is usually pretty easy, but calling the peak in August is tough so we still have a few more weeks of ERCOT load watching to do. Remember, if you need someone to help you with this, call these guys

ERCOT July 2013.png

Heating Oil - To Lock or Not To Lock The Price

While most city-folk have natural gas these days, there are still millions of people in the Northeast U.S. and eastern Canada who heat with No. 2 fuel oil. While the reasons for sticking with oil are varied, most oil heating customers today don't have access to natural gas. Its important to note that before 2008 there were times when oil heat was actually less expensive than natural gas and its not out of the question that it won't happen again.  Many fuel oil distributors will also be quick to remind you that No. 2 fuel oil has never blown up a building. Despite this, fuel oil distributors are seeing their routes shrink each winter as the natural gas utilities pick-off their customers. In Connecticut and Maine, the State is actively encouraging customers to switch to natural gas and even subsidizing the expansion of natural gas infrastructure.

Towards the end of the summer, many heating oil customers are asked by their distributor if they'd like to "Lock-in" their oil price for the coming winter. This may seem like a daunting and opaque transaction for the average residential or small commercial consumer. There are several elements and risk factors that are included in any fixed priced offer for oil.  

The first and most obvious risk is the price. Heating oil is a refined petroleum product that is nearly identical to diesel fuel. The price is largely determined by the input cost of the oil into the refinery and the supply of refined heating oil in the marketplace. East coast refiners make adjustments each fall to build stocks of heating oil and the relative supplies are determined by the degree to which refiners calibrate their plants to produce refined product (e.g., gasoline, kerosene, jet fuel, asphalt, etc.). Heating oil futures are traded on the NYMEX under the symbol HO and each month has its own contract. The contract size is 42,000 gallons (1,000 barrels) and the delivery point is New York Harbor.  After May 2013, the specifications for the NYMEX heating oil contract will require a sulfur content of less than 15 ppm and heating oil and diesel will be one and the same insofar as the NYMEX contract is concerned. Heating oil with the higher sulfur content will persist for a while in physical markets as some Northeast US states don't mandate the switch to low sulfur until 2018. 

No one takes delivery in New York Harbor so there is a basis differential in the price between the settled NYMEX heating oil contract and the local spot market. The graphics below show the current NYMEX heating oil futures curve as well as recent spot prices for heating oil in Boston as reported by the Oil Price Information Service. Note that heating oil futures are backwardated just like Brent futures (generally speaking, going long into backwardation is a bad move). For most customers, the delivered price of oil to their tank will be anywhere from $0.30 - $70/gallon higher than the spot prices reported here since the fuel oil distributor needs to mark up the fuel to pay for delivery costs.

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The second risk factor is usage since it represents a volumetric risk. In a cold winter a customer will use a lot more oil than in a warm winter. As a result, the volume of oil in any fixed price deal is a moving target for the counter-party offering the fixed price. Some "price lock" offers will include a limit on the volume of oil offered at the fixed price to help mitigate this risk. Although the customer will use oil continuously during the heating season, the fuel oil distributor will need to make discrete purchases and deliveries of oil to the customer's tank. As an example, the oil that a customer consumes in December would likely have been purchased and delivered in November. As a result, the November oil price is relevant to December's usage. 

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Many people falsely presume that by locking a price per gallon for heating oil that they will attain budget certainty. While fixing a price per gallon will hold one variable steady, absolute budget certainty will still prove elusive. The column bars in the graphic above represent fuel oil deliveries to a medium size commercial customer in Eastern, MA during the 2012-2013 heating season. The fuel oil distributor makes an oil delivery approximately every 10 days during the heating season. Since actual consumption varies with the weather, there is a significant difference in delivery volumes and as a result, the total cost of each delivery varies widely. The red squares represent the total cost of each delivery with the most and least expensive deliveries costing $2,791 and $1,179, respectively. The number and size of deliveries is based on consumption which is based on the weather which can be highly unpredictable.

So what is a fuel oil user to do? At ETE, we generally offer two pieces of advice. The first is that "locking in" a price for oil for residential or small commercial seasonal quantities is an extremely inefficient transaction with multiple middlemen . The second is that if a customer feels strongly that they need to be able to contain some of the budget risk in their fuel oil spend and they can "lock in" a price at an acceptable level, they should do it so long as they know they are paying a premium to do so and that the actual spot price could be lower when winter comes. The graphic below helps illustrate this choice.

Lock-in graphic.png

If your facility is struggling with a decision to lock in an oil price, call us. We can probably help. 

Power Plant of the Week - William F. Wyman Station

If Central Maine Power (CMP) is your utility, you owe a debt of gratitude to the Wyman family. In 1899, Walter Wyman purchased a dam on the Messalonskee stream near Oakland, ME. In the early years of the 20th century, Walter Wyman built what would later become the CMP by building out new service and acquiring smaller electric companies throughout the State of Maine. For the Wyman family, running electric utilities was a family business and Walter's son William became the CEO of CMP in the late 1940s. William F. Wyman would run CMP until 1962 when he passed away. 

The post war years were characterized by rapid load growth in Maine and CMP continued the build-out of their system to keep up. In addition, CMP was active in working to recruit industry to locate in Maine. The William F. Wyman station was built in the mid 1950s on Cousins Island in Yarmouth, ME. This location offers several advantages including access to water (for cooling water and barge deliveries of oil) and proximity to the load in the Portland area. The bridge to Cousins Island was built to accommodate the construction of this plant. Click here to see the plant on Google Maps.

William F. Wyman Power Plant

William F. Wyman Power Plant

There are currently four steam turbine units at the William F. Wyman station and all are fueled by Residual Fuel (a.ka. No. 6 fuel oil). Units 1 and 2 went online in 1957 and 1958, respectively and have nameplate capacities of approximately 50 MW. Unit 3 came online in 1963 and has a capacity of ~ 115 MW. Unit 4 is identifiable by the large smokestack,   was completed in 1978, and has a nameplate capacity of ~ 600 MW.   CMP sold the plant to Florida Power & Light in 1999. Florida Power & Light subsequently re-branded its deregulated operations as NextEra Energy in the late 2000s. There are also several minority shareholders in the plant who own an approximate 12% interest of Unit 4.

For many years, pollution associated with this plant was considered a significant problem in Downeast Maine and raised the ire of local environmental activists. NextEra Energy did invest in pollution control technology at the plant in the early 2000s, but argued against a state-of-the-art upgrade citing the age of the plant and its uncertain future lifespan. The deregulated ISO-NE energy market has indirectly solved the pollution problem associated with the plant since it is rarely dispatched due to its high costs. Except during the hottest days in summer or the coldest days in winter, natural gas is less expensive that residual fuel. As a result, natural gas fired power plants are able to undercut the William F. Wyman station on price and keep it out of the market unless demand exceeds the ability of hydro, nuclear, renewable, and natural gas assets to supply the ISO-NE load.  The graph below shows the net generation in Megawatt hours for Units 1-4 at the plant and its clear that this plant has become a peaking resource for peak winter and summer conditions. Although the plant was needed in January and February 2013, its output was still only about 10% of its maximum potential monthly output capacity.

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NextEra Energy recently announced that it is looking to sell the William F. Wyman station. Due to its age, infrequent dispatch, and difficult economics, NextEra says that this plant is no longer a strategic fit. While NextEra hasn't publicly announced an asking price, our guess is that its around $1,000 o/b/o, cash only. If you are in the market for an uneconomic generating asset with spectacular water views, William F. Wyman could be yours. Also, if you live in Yarmouth, ME your property taxes are going to increase once this plant gets sold and its assessed value is reset.

 

July 2013 ISO-NE Heat Wave and Historical Peak Days

For anyone who was outside during the week beginning July 15th, 2013 anywhere east of the Rocky Mountains, it was hot, like really hot. As a result, its highly likely that many commercial and industrial customers set their Installed Capacity (ICAP) or Peak Load Contribution (PLC) tags that week. We explained the ISO-NE capacity market several blog posts ago and sometime soon, we plan to cover the capacity markets for NYISO, PJM, and Ontario. In this post, we plan to focus on ISO-NE and the summer load patterns to date.

The ISO-NE grid is strongly summer peaking and the hottest days result in system loads much higher than average. The table below shows the daily peak system loads on the top 10 highest load days of the last eight years.  In this time period, all top 10 load days occurred during the summer months and the last time a top 10 load day occurred during winter was 2004. Note the separation between the peak day for each year and the 5th highest or tenth highest day. Its a significant difference in most years. Also note that the highest load day ever recorded in the ISO-NE load zone was August 2, 2006 when the system load peaked at 28,130 MW. 

ISO-NE Top 10 Load Days.png

For interval metered customers, knowing the peak load hour is significant because the customer's demand during the peak load hour will determine their ICAP Tag. For more information, check out our previous blog post on this topic here. Many large industrial customers try to predict when the ISO-NE peak load hour will occur so that they can preemptively shed load. These customers do this to reduce their ICAP tag and for each MW of ICAP tag that a customer can avoid they are able to save approximately $36,000. Predicting the peak load hour can be tricky on the hottest days because its not uncommon for the load to deviate from the forecast given by ISO-NE in the morning. Any of the following can cause significant deviations in the actual load vs. the forecast: late day thunderstorms; activation of demand response; an afternoon sea breeze at the coast; or the secondary effect of large customers shedding load when they think a peak is imminent. 

While its impossible to know if we've already set the system peak for 2013 (we won't know for sure until the summer is over), its very likely that it happened on Friday, July 19 between 4 - 5 p.m. The graph below shows ISO-NE daily peak loads through July 24th, 2013, color coded for weekdays vs. weekends. The load pattern for the summer was pretty typical for June and early July. There were four days where the load exceeded 24,000 MW prior to July 15th, 2013 and these high load days coincided with high temperatures in Southern New England ( about 90° F). In each case, the high temperatures did not last more than two or three days and the load dropped significantly when temperatures receded. The week beginning July 15th, 2013 contained a heat wave of an exceptional intensity and duration. New England experiences heat waves like this only two or three times per decade. The graph shows clearly how each day of the week experienced a higher peak load than the day before despite there being similar temperatures each day. This incrementally increasing load each day during a heat wave is a common phenomena since building envelopes absorb and retain increasing amounts of heat as the heat wave progresses. As a result, air conditioning systems have to work much harder on the third or fourth day of a heat wave than the first to overcome the heat present in the building envelope. 

ISO-NE July13Load.jpg
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The table to the right shows the ISO-NE system peak load days and hourly intervals over the last several years. Many people consider the summer of 2009 to be a total outlier given how cool and rainy that summer was. Although the week beginning July 15th, 2013 did not set an all-time peak in ISO-NE (as it did in NYISO), it did record two of the top 10 load days in ISO-NE's history and Saturday July, 20th was the highest weekend load ever recorded. Although its likely that the system peak for 2013 has been set, early August can get quite hot so we'll have to wait and see.

Power Factor and Demand Charge Penalties

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

PowerFactor.png

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

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

PF Triangle.png

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

Water Analogy.png

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

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

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

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

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

Excerpt from the NStar B7 rate tariff

Excerpt from the NStar B7 rate tariff

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

kVar2.png
Excerpt from the West Penn Power rate tariff for Schedule 30

Excerpt from the West Penn Power rate tariff for Schedule 30

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

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. 

ERCOT 4CP - June 2013 Review

The Electric Reliability Council of Texas (ERCOT) has a unique capacity cost allocation program to recover transmission costs for the ERCOT grid. This cost allocation method is referred to as 4CP because it refers to the four critical peaks, namely the peak hour on the ERCOT grid for each summer month. Transmission costs are allocated to each interval metered commercial and industrial customer based on their measured demand during the ERCOT peak hours that occur in June, July, August, and September. At the end of the summer, each customer is assigned a tag based on their usage during each peak hour. This tag is found by multiplying the customer's demand during each monthly peak hour by 25% and summing the results for all four months.  The tag then takes effect in the following year for billing purposes.

Generally speaking, each 1 Megawatt (MW) of capacity tag for ERCOT 4CP results in an additional annual cost of approximately $25,000. For customers with large loads or a low opportunity cost of interruption, it makes sense to try to predict when the ERCOT monthly system peak hour will occur and proactively shed load to get a lower capacity tag. There are several services out there that offer prediction services as to when ERCOT peak hours may occur. Thomas Engineering is one company that offers such a service and Energy Tariff Experts recommends them. Since the total cost avoidance opportunity comes out to ~ $25,000 and it's based on coincident demands over four months, then 1 MW of coincident demand in each summer month costs ~ $6,250 (25k/4). In most months, customers can be expected to curtail at least four times for a period of 2.5 hours. As a result, customers must have an opportunity cost of curtailment below $625 (($6,250/(2.5 x 4)) per hour per 1 MW of demand for managing a 4CP tag to make economic sense.

ERCOT 4CP June 13.png

Although ERCOT doesn't release final information regarding the exact monthly system peaks until the fall, the preliminary data from ERCOT is good enough for any ERCOT 4CP participant to see how they did for June.  Luckily, June 2013 got off to a slow start and didn't get hot until the last week. The graph at the right shows the ERCOT daily peak system loads for each day in June. The last week was a scorcher and the monthly peak occurred on June 27th in the hour ending at 17:00.

ERCOT 4CP June 13_1.png

Calling the ERCOT system peak load can be quite difficult. Although the ERCOT system peaks on the hottest days, the weather in Houston and Dallas determines which days set peaks. If there are thunderstorms in either city, its unlikely that the day will set a system peak for the month. The graph to the right shows the load profile for ERCOT system demands for each day in June 2013. The three highest days have been color coded for ease of viewing. You'll note that the days with the potential to set monthly peaks really don't begin to separate until the early afternoon.

 

ERCOT 4CP June 13_2.png

Its nearly impossible to make an accurate potential peak day prediction for ERCOT before noon on any day that is very hot. The second graphic shows the highest load days in June, zoomed in just to show the afternoon hours. You'll note that the separation between the top three days was not very large and either of the top two days could have ended up setting the peak for June. July isn't done yet, but the week of July 8th sure was hot so we may or may not have set the peak for July. 

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.

MA Solar Carve-Out Chaos

So by now, most people in the solar industry know that the MA Solar Carve-out is done.  The big question on everyone's mind is "What's next?". The Massachusetts Department of Energy Resources (DOER) hosted a stakeholder forum to provide an update on future policy support for solar on June 7th. At this point, its still a little hazy as to exactly what the future program will look like, but DOER has significantly expanded on several ideas presented during the 3/22/2013 policy session, most notably the Solar Renewable Energy Credit (SREC) Factor (more on this later). 

The other big question is where to draw the line regarding eligibility in the current 400 MW Solar Carve-Out (SCO) program. The SCO was born through "Emergency Regulations" in January 2010 and it will close through "Emergency Regulations" as DOER needs a way to determine which projects will qualify for the 400 MW cap and which ones won't. Right now, they have more applications than capacity and will need to determine which projects make the cut and which ones will need to wait for the successor program. DOER has stated that they will expand the current 400 MW cap for projects that "are demonstrably well invested in the development cycle and for small projects to continue to proceed." This also means that the steady state SREC compliance obligation for years 2014 - 2022 will need to be adjusted upward to accommodate the expanded capacity ceiling of the SCO. Here is what we know so far regarding who will qualify for the existing SCO:

  • All residential and small commercial (<100 kW) projects will qualify until the regulations for the successor program are promulgated
  • All projects with utility Interconnection Service Agreements signed prior to June 7th, 2013 so long as they "meet proscribed project construction timelines" 
  • "Proscribed construction timelines" means: Authorization to Interconnect before 12/31/2013; or 50% of total construction costs are expended by 12/31/2013 and Authorization to Interconnect is granted by 3/31/2014.

As for the future, Energy Tariff Experts (ETE) is encouraged by the ambitious policy support for future solar build-out in MA. There are several good things in the current DOER proposal for the successor to the SCO. There are also some concerning aspects of the current proposal, namely the complexity of the proposed regime which at first glance seems like a highly complex, Rube Goldberg contraption that will be hard for many to grasp. There are also several inherent contradictions in the current proposal regarding stated goals and likely outcomes for ratepayers.

First, lets start with the good things. ETE is especially encouraged that the proposal for the successor program includes provisions for the following:

  • A long policy horizon to support the build out of ~ 1,200 MW of additional solar PV
  • Ten year term limits on SRECs
  • A Clearinghouse Auction price support mechanism
  • Forward SREC minting for small/residential PV installations
  • Consideration of plans to mitigate aggressive ground mount developments (e.g., cutting down forested land to build solar PV arrays) through land use criteria and/or inter-agency regulation.

Now lets discuss the contradictions. MA DOER states that they are concerned about ratepayers costs and want to achieve solar cost parity with the current Class I REC market. At the same time, they propose a mechanism to "manage supply" by limiting the amount of larger ground mounted systems accepted into the marketplace. By having a mechanism to "manage supply", DOER can keep SREC prices high and avoid "unfettered market expansion and oversupply." It seems that DOER is very concerned for the welfare of solar developers, but if there is to be a REC market why not let market forces drive the rate of build outs? Why should DOER have a mechanism to control growth? DOER's current proposal to manage the supply of larger ground mounted systems is worrisome because their proposed criteria are as follows: " Managed supply will be qualified competitively based on criteria including, for example, price (applicants bid SREC Factor), and non-price criteria such as land use attributes, tree cutting, development timeline and likelihood of success, local benefits, etc."  These non-price criteria could to open the door to politicization of the acceptance process, which would be a bad thing. If DOER is worried about solar ground mounts, they should promulgate regulations around land use criteria or limit the size of SREC eligible ground mount developments instead of creating an opaque mechanism for "managed supply."

MA DPU, Post 400 MW Solar Program Policy Design Stakeholder Briefing, June 7th, 2013. Slide 20

MA DPU, Post 400 MW Solar Program Policy Design Stakeholder Briefing, June 7th, 2013. Slide 20

The proposed SREC Factor, while conceptually coherent, could prove to be very difficult to implement in practice. DOER's stated goal is to achieve cost parity between SRECs and Class I RECs. The SREC Factor is the mechanism they plan to use to achieve this as the SREC factor will be used in a formula that will determine the REC payment for the output of PV systems built in each year of the successor program. The easiest way to think about it is to compare it to a blending process. Each MWh of Solar PV will be split between SRECs and Class I RECs. At the beginning of the program, small systems will get 1 SREC for each MWh produced (see graphic). Over time, as costs decline for new systems, the SREC factor will decrease and small units will get less SRECs and more Class I RECs and therefore the dollars received through REC payments will be incrementally lowered each year for new capacity installations. Note that larger systems will start off with a lower SREC factor since they require lower SREC payments in order to be economic. The table below shows how DOER is thinking about this. They plan to assign progressively declining SREC factors for different classes of systems based up the cumulative MW of solar build out to date. 

MA DPU, Post 400 MW Solar Program Policy Design Stakeholder Briefing, June 7th, 2013. Slide 21

MA DPU, Post 400 MW Solar Program Policy Design Stakeholder Briefing, June 7th, 2013. Slide 21

The graphic to the right below provides a visual illustration as to how the SREC Factor will be used to determine the dollar value of the RECs generated for each MWh of solar PV production. The SREC factor is essentially the multiplier used to divide

SREC Factor Illustration.png

the 1 MWh up into Class I REC and SREC fractional components. Each fraction is then multiplied by the then current price of each REC type to determine the REC incentive that the owner of the solar PV system will receive. Now, the contradiction with this mechanism is that it looks less like a REC market and more like a Feed-in-Tariff (FiT) in disguise. DOER is very concerned with price stability and predictability, but creating a FiT is beyond the scope of what they can accomplish in the next few months to keep the solar industry going in MA. DOER seems overly concerned with a New Jersey style bust in the solar market and the price support mechanisms in the current proposal along with the declining SREC factors are meant to prevent a boom and bust cycle of development. The future solar regime in MA looks like it will be very friendly to developers and expensive for consumers (at least in the near term). At ETE we have simple advice, if you have a sunny roof in MA, go solar.