Sunday, September 21, 2014

Down by the Water* - Hydro Power in New Hampshire – Part 1

My office is in Manchester, in Franklin Pierce University’s graduate school which is located in one of the renovated mill buildings located on the Merrimack River. From the conference room there is a great view of the river and the upstream Amoskeag dam. This is a 30-foot high, 710-foot long concrete dam that holds back the Merrimack River at this point so that the water can be directed through the turbines at the Amoskeag Power House located on the western bank of the Merrimack.  These turbines have a combined generating capacity of 16 MW. The photos below show my view of the dam wall and a Google Map satellite image for an overhead view. This dam was originally commissioned in 1924 to service the Manchester mills. While gazing at the river this week during a meeting, I decided it was time to turn my attention to the topic of hydro power in New Hampshire. This post is the first in a multi-part series on this topic.

Man has utilized the power of water (hydro power) for centuries. In the late 1700s and into the 1800s, advances in technology, powered by running water (and eventually by steam) is what lead to the industrial revolution. Throughout New England, textile mills were established along the main rivers, most notably the Blackstone River that runs down through Worchester, Massachusetts into Rhode Island and the Merrimack River that follows a route through New Hampshire into Massachusetts. The river flow turned water wheels and turbines which, through a system of gears, shafts, and belts, were used to drive machinery inside the mills.

In the 1880s, water-driven turbines were combined with electric generators to generate the first hydroelectricity, and in 1882 the world's first hydroelectric power plant started operation on the Fox River in Appleton, Wisconsin. From that point on, the use of hydroelectricity grew phenomenally and, in 1940, hydro generated 40% of all electricity in the US. Since then, demand for electricity has increased ten-fold, but natural gas-, coal-, and nuclear-fired operations were established to fill the need. Hydro power output grew, but its share of electricity production has dropped off to about 6 to 8% of the electricity generated in the US today.

Hydro operations range in size from the very large 6809 MW Grand Coulee Dam in Washington state, the 2515 MW of the Robert Moses Niagara Power Plant and the 2080 MW of the Hoover dam on the Colorado River to “hobby” projects less than 1 kW in capacity. (Remember there are 1000 kW in a MW.) There are about 1750 hydropower operations in the US: most of them are much smaller than in size than the very large Hoover Dam operation which we usually associate with hydropower.  In fact, most hydroelectric operations in the US are much smaller - almost 90%  are less than 30 MW in size.
Hoover Dam Hydroelectric Plan

All hydropower operations, whether private, municipal, or state-owned, are licensed by the Federal Energy Electricity Commission  (FERC) – the  federal “godfather” of the electricity business. There are 41 FERC-licensed hydro operations in NH, ranging in size from 136 MW to 58 kW.  Small projects, such as those less than 10 MW installed on an existing dam or those of less than 40 MW installed on a waterway used for another purpose (such as an irrigation canal), are exempt from FERC licensing. There are 43 such exempt facilities in NH, ranging from the 3.5 MW Gregg’s Falls operation on the Piscataquog River in Goffstown to a 5 kW operation on Marden Brook. FERC licenses often involve combinations of hydro operations run by a single operator on a stretch of water:  for example, the three PSNH operations on the Merrimack River are combined into one license. I also noted that the very large Moore and Commerford hydro plants on the Connecticut River are listed by FERC as Vermont operations. These licensing/classification artifacts can cause confusion, especially when data on generation, as provided by the Energy Information Agency (EIA) and used later in this post, is reviewed.

There are many different ways of classifying hydro operations. The first is by size. Large hydro plants in the US are generally considered to be those above 25 MW in capacity but international standards consider those above 10 MW to be large. Most of the hydro plants in New Hampshire are small operations: within this class there are subclasses which typically have the following size ranges:

·                                Mini                <1 MW
·                                Micro              <100 kW
·                                Pico                <10 kW
·                                Family             <1 kW

To give you a sense of what these capacities mean, it is important to remind ourselves of the difference between power and energy.  I discussed this topic in the I’ve Got the Power! blog a while ago. As a reminder, remember that electrical energy is the ability of an electric current to do work − such as producing motion, heat, or light. The units of electrical energy are kilowatt hours (kWh) or megawatt hours (MWh). There are 1000 kWh in one MWh. Electrical power, on the other hand, measured in kilowatts (kW) or megawatts (MW), is a capacity, i.e., the rate at which energy can be produced from a generator. Large generators, which can produce more energy per unit of time, naturally have larger capacity or power ratings.

The confusion between power and energy often stems from the similarity of the units: kilowatt hours or megawatt hours are energy units, and kilowatts or megawatts are power units. However, it is important to understand that even though the units seem similar, there is a world of difference between them. This difference stems from the simple mathematical relationship between energy and power;

Energy = Power x time.

I find it is always useful to understand these relationships from a homeowner’s point of view. Consider that an average US household uses 11,000 kWh per year of electricity (~900 kWh per month). If you had to generate that electricity yourself and you were going to do it over 24 hours a day for 365 days per year, you would need generator with a power rating of 1.3 kW.

The calculation would be done as follows:

Energy = Power x time
Power = Energy / time
Power = 11,000 kWh/(365 days x 24 hours/day) = 1.3 kW.

Of course, this calculation is based on a daily average, but our daily electricity use is actually rather “lumpy”:  there is a first peak in the morning as we turn on the lights, make coffee, heat up the house, and take hot showers, followed by a second and larger peak in the late afternoon/evening when we are making dinner, watching TV, doing the laundry, turning on the electric blanket, reading this blog, etc. If you were to actually buy a generator, you would want a unit that has a capacity of more than the average 1.3 kW so that it could handle the peaks in usage. This is why backup generators for homes often have sizes of the order of 5 kW to 15 kW. But I digress somewhat (I may come back to the topic of home generators in a future post)….

The second classification of hydro plants is by type of operation. The three main types are:

  • Reservoir or Pond-and-Release Operations: We most commonly associate these with hydropower and they involve large concrete dams holding back enormous reservoirs of water with the power plant at the base, as shown in the Hoover Dam picture above. The reservoir provides for a great deal of storage and steady power generation even during the dry season. These operations usually involve the upstream flooding of large tracts of land and significantly impact downstream water flows. The water level in the reservoir can also fluctuate greatly, depending on the incoming water flows and the discharges through the power station.
  • Run-of-River Operations: These hydroelectric plants depend on the natural drop in the river elevation. A portion of the upstream river flow is sometimes diverted through a large pipe (called a penstock) to a downstream generator plant, after which the water flow is reintroduced into the river (see the figure below). These operations often have dams at the upstream location to provide the water diversion point but their storage capacity, called pondage, is limited and, as such, these operations are more subject to the vagaries of seasonal precipitation and natural river flows. With limited storage, the reservoir level tends to remain fairly constant – excess river flow simply spills over the top of the dam. Electricity production can therefore vary substantially over time. Because these operations don’t involve large amounts of storage or flooding of large acreages of land, they tend to viewed as more environmentally friendly or “greener” than the larger reservoir operations.
  • Pumped Storage: These operations involve pumping water from a river uphill to a reservoir at a higher elevation during low electricity demand and low cost periods. When electricity demand increases and prices are high, these operations then run in reverse and the water in the reservoir is drained through a turbine back into the river, generating electricity in the process. There are a three of these operations in New England with a combined capacity of 1696 MW.


Source: IPCC

In NH, we do not have any pumped storage operations but we have reservoir and run-of-river operations.  Data from the EIA indicates that there are 92 hydro generators in NH with a combined name-plate capacity of 446 MW and a total winter capacity of 511 MW. The ten largest NH hydroelectric operations are listed below.  The Moore and Comerford dams, located on the Connecticut River which runs between New Hampshire and Vermont, are the largest hydro operations in all of New England. All operations listed are individual dams, except for the Great Lake Hydro-owned operation on the Androscoggin River in the Berlin area which is a series of different dams and 21 generating facilities. The largest PSNH-owned operation in NH (and the one that distracts me during meetings)  is the Amoskeag dam on the Merrimack River.


Source: EIA

As a wrap-up for this post, I thought a comparison with other New England states would be interesting. The table below lists total electricity production capacity (the power of the generator) and hydro capacity by state for 2012, as well as total production of electricity and hydroelectricity. The data include conventional hydro only and excludes pumped storage operations. We can see that Maine is the “hydro powerhouse” of the New England region, with the largest capacity, followed by NH. The upper New England states, New Hampshire, Vermont, and Maine  provide the bulk of the region’s hydro generation capacity.

I note with interest that, even though Maine total hydro capacity was only 17% of its total generating capacity, 26% of their electricity output for 2012 was generated from hydro. This means that their hydro plants worked very hard in 2012, which is indicated by the highest capacity factor for their combined hydro plants. (Recall from I’ve Got the Power! that capacity factor is the ratio, expressed as a percentage, of the actual electricity output from a generator over a year compared to the theoretical output if the unit operated 24 hours/day 365 days per year.) The comparative numbers for NH are quite different. In orange I have highlighted that hydro represented 10% of NH generating capacity but, in 2012, it was, surprisingly, only responsible for 7% of the NH total electricity output. The capacity factor of all NH’s hydro plants, in yellow, was therefore an extraordinary low 33%.


Source: EIA

This anomaly is quite striking and some follow-up research is warranted. It is clear that hydro power is intriguing topic and I plan to continue my explorations in future posts. Now, when I gaze out the windows at the Merrimack River and the upstream Amoskeag dam during faculty meetings, my colleagues can be assured that my distraction is not idle daydreaming; instead I will be thinking of river flows, generating plants, and capacity factors!

Until next time, remember to turn off the lights when you leave the room.

Mike Mooiman
Franklin Pierce University


(*Down by the Water – A great tune by one of my favorite indie groups, The Decemberists. These guys are great song writers and I always look forward to their new releases. Here they are from Austin City Limits – the best music show on TV. Enjoy Down by the Water.)


Saturday, August 23, 2014

Extraordinary Machine* - ISO New England

I had the opportunity early this summer to take a week-long course from the folks at ISO New England (ISO-NE) on Wholesale Electricity Markets.  ISO-NE is the regional organization that is essentially responsible for keeping the lights on in New England. ISO stands for Independent System Operator. This is the organization that coordinates the generation and transmission of electricity in New England through a variety of regulated and free market mechanisms.

In previous blogs, What’s It All About, Alfie? and Wind in the Wires, I discussed the structure of the utility industry and particularly the electrical utility industry. There are three aspects to the electrical utility business, as shown in the figure below: there is the generation of power, typically at a large power plant located in a central location, then there is the transmission of electricity over long distances from the generation point to towns and cities, and, finally, there is the distribution of electricity through the community via the sub-stations, transformers, and wires to individual homes and businesses. 


ISO-NE is the organization that coordinates the generation and transmission aspects of the electricity business. It is your local electrical utility, such as PSNH, Unitil, or Liberty Utilities, that is responsible for the distribution step, which involves drawing the electricity from the transmission lines and getting it to your home and place of work. ISO-NE is not reading your individual electrical meter - that is also the task of your local electrical distribution company. It is important to note that ISO-NE does not own or operate generation plants or transmission lines. Instead, through a variety of market mechanisms, it is responsible for the coordination of generation and supply by a host of generation and transmission companies.

This turns out to be an extraordinarily complicated task because electricity cannot be stored (or very little of it) and so there needs to be a consumer for every electron of electricity produced by a power generation plant at every minute of the day. When you increase your demand for electricity by turning on your laptop or tablet to read this blog, someone needs to ensure that generating companies are supplying just the right amount of electricity to do so: that is what ISO-NE does.

ISO-NE operates the electrical grid in the six New England states of New Hampshire, Vermont, Maine, Massachusetts, Rhode Island, and Connecticut and has three primary responsibilities:
  1. Operating the Power System: ISO-NE ensures the correct balance between electricity supply and demand every minute of the day by centrally coordinating the generation and transmission of electricity in the New England region and into (and from) other neighboring regions, if necessary.
  2. Supervising Wholesale Electricity Markets: ISO-NE provides and supervises the market platforms on which wholesale electricity is bought and sold.
  3. Power System Planning: ISO-NE assures that present and future electricity needs are meet through the development of reliable generation and transmission systems.
In the days before electrical deregulation, electrical utilities, such as Public Service of New Hampshire (PSNH), were given a monopoly to provide electrical service to large regions. As such, the utility was responsible for the generation, transmission, and distribution of electricity across the region. This was done largely through operating its own generation plants, running the electricity through its own transmission lines, and supplying it to its own customers through its own distribution network. However, as noted in Shall I Stay, or Should I Go?, this model has changed as consumers have demanded choice and competition. We have been swept up in the deregulation wave that has worked to unbundle the electrical industry and break it up into separate generation, transmission, and generation companies, and to allow competition in each of these areas. Although deregulation has had varying levels of success, it soon became clear that this environment required a single controlling entity to coordinate open access electricity supply, transmission, and use across all a range of independent and competitive regional companies and regulated utilities, hence the need of an Independent System Operator such as ISO-NE. 

The seeds for ISO-NE were sown in the 1965 Northeast blackout that affected some 30 million people in Ontario and large parts of New England, New York, and New Jersey. This blackout was caused by a single poorly set relay at a New York power plant that created a series of cascading electrical surges, tripped relays, and imbalances that moved through the electrical grid and shut down generation plants. In the aftermath of the blackout, several reliability councils were set up to improve coordination between electrical utilities. One of the organizations formed in 1971 was New England Power Pool (NEPOOL), which was a trade organization of New England power companies. The focus of their work was to improve cooperation and coordination among the regional power utilities. In the process, they organized much of the NE electrical grid and established a central electricity dispatch organization.

For almost three decades, NEPOOL was responsible for the coordination of the NE electrical grid, but, in the 1990s, with the advent of deregulation, the Federal Energy Regulatory Commission (FERC) – the Federal “godfather” of the electricity business – decided that deregulation required open access to the electrical grid by independent power companies and well-run competitive markets. FERC concluded that this was best done under the auspices of an independent organization, rather than a trade organization of existing participants which may not be open to increased competition. ISO-NE is one of several regional organizations that were established in 1997 to monitor deregulation, establish open and competitive wholesale markets, as well as coordinate and operate the regional electrical grid. Essentially ISO-NE assumed some of the functions that had been carried out by NEPOOL. In 2005, FERC provided ISO-NE with greater authority and independence over the transmission grid and designated it as the six-state Regional Transmission Organization or RTO. The map below shows the location of other ISOs or RTO in North America.

Today, ISO-NE is responsible for over $10 billion of wholesale electricity transactions from 400 market participants. It is a private, non-profit organization with operations located in Western Massachusetts. It has about 550 employees, most of whom are power system engineers, computer scientists, and economists. ISO-NE does not have trucks and power line crews that go out repair the grid. That is the responsibility of the transmission and distribution companies. The ISO-NE folks do not get their hands dirty: it is a coordinating, monitoring, and planning body for the electrical grid.
Here are some key facts about ISO-NE:
  •    Serves 14 million residents with 6.5 million meters across six NE states;
  •    Coordinates 32,000 MW of generating capacity;
  •    Coordinates 350 generators;
  •    Covers 8400 miles of high voltage transmission lines;
  •    Highest peak demand for electricity ever recorded is 28,130 MW;
  •    Peak load in 2013 was 27,379 MW;
  •    Generation of electricity in 2013 was 129,336,000 MWh;
  •    Average Day Ahead Wholesale Price in 2013: $ 54.42/MWh (= 5.4 cents/kWh);
  •    $8 billion in transactions from electricity sales in 2013;
  •    2013 operating expenses: $157 million.


ISO-NE Control Room (Photo Courtesy of ISO-NE)


ISO-NE has created several markets, the most important of which is the wholesale market for buying and selling electricity and which accounts for the bulk of ISO-NE transactions. Another important and growing function is the capacity market, which is a forward market in which bidders commit generation capacity that will meet the electricity needs in the future. For example, a new start-up power plant can auction off its generation capacity to supply electricity in three years’ time. Of course, if this future capacity is bought, the start-up is obligated to deliver that generating capability in three years. This market provides an additional revenue stream for power plants, it allows capacity planning at least three years out, and it provides incentives for the construction of new power plants.

As a result of my research, I now have a much better understanding of ISO-NE and their function. My most important takeaway, however, was that I was simply stunned at the engineering and economic complexity involved in getting electricity from generators, moving it across transmission lines, and getting it to users in a complex deregulated market. As I noted earlier, ISO-NE folks do not get their hands dirty repairing transformers and power lines but they have built and are responsible for a very complex machine. A useful way of understanding this machine is to view it, as other authors have, as a mechanism responsible for controlling three types of flows, as in the figure below.  It is responsible for the flow of information about generation, transmission, and demand, which leads to transparent market operations and both short- and long-term planning for the electrical grid. It is also responsible for the coordination and flow of electricity from generators to users across transmissions lines. Finally, through its market mechanisms, it is the conduit for money flows from buyers of electricity or generation capacity to sellers.


I am very impressed with this machine and now understand more completely the need for an organization like ISO-NE. We often hear grumbling in NH that we export a great deal of the electricity we produce. That is true, but only up to a point. It is important to understand that NH is not an “electrical island” responsible for its own generation and use of electricity. That is old school “PSNH will take care of everything for New Hampshire” thinking. We now live in a time of deregulated (or partially deregulated) markets. The State of New Hampshire is part of the New England grid and, along with our neighbors, we generate, transmit, and use electricity. Largely due to the Seabrook Nuclear Plant in Portsmouth, we presently generate more than we use so other NE users benefit from NH generation capacity, but, should there be an interruption of supply from Seabrook, we will be very grateful that we are indeed part of the NE grid. Likewise, access to the NE markets allows us to participate in long-term planning and in large wholesale electricity markets whose structure and competitive nature work to keep wholesale electricity prices down.

There is, of course, a cost associated with a controlling body such as ISO-NE. The 2013 operating expense for ISO-NE was $157 million, which we as rate payers end up paying for. If we divide the costs of ISO by the electricity produced in 2013, this yields a figure of about 0.11 c/kWh. For an average household using 800 KWh per month, the ISO-related costs turn out to be about a dollar per month. From my perspective, that is cheap insurance for a reliable electrical supply and efficient markets.

Until next time, remember to turn off the lights when you leave the room—and when you do so, think about the extraordinary machine* that adjusts to that small reduction in electrical demand. It is indeed remarkable.


Mike Mooiman
Franklin Pierce University

(*Extraordinary Machine – A cool little old timey tune by the extraordinarily talented Fiona Apple. Here is a performance from the Today Show. Enjoy.)

Tuesday, June 24, 2014

The Price* - Natural Gas Prices in New Hampshire

I have been away for a while working on energy projects, keeping my energy students busy, and attending conferences. I also had the good fortune to attend a week-long course on the wholesale electricity market in New England that was arranged by ISO-NE, the organization that runs the local electrical grid. I learned a great deal and came away very impressed with the marvelous machine that organizes the electricity market and supply here in New England. I am planning to write about this in a future blog. Our electricity market in New England has become highly dependent on natural gas supply and pricing so I have been keeping an eye on natural gas prices, trying to understand their movement and what drives them.  As is common in the energy world, “price” means very different things to different people and, when doing research on natural gas prices, it can become rather involved rather quickly.

As it turns out, there are three natural gas prices of interest to us here in NH. The first, and on which all the other prices are based, is the basic commodity price for natural gas. This is most commonly referred to as the Henry Hub price and it provides the basis for much of natural gas pricing throughout the US. The Henry Hub is a location in Louisiana where several gas lines converge and radiate out across the US. Although not all the natural gas in the US is routed through the Henry Hub, it is nevertheless the agreed delivery and receiving point for traders and dealers in the wholesale gas market. It is likely that when you hear discussion about natural gas prices or read about them in the financial press, it is the Henry Hub prices that are being discussed.

The challenge here in New England is that we are a long way from Louisiana and other natural gas sources and gas has to be routed through many hundreds of miles of pipelines and multiple compressor stations to get it to us and there is, of course, a cost associated with its transportation. This is reflected in the second of the natural gas prices, which is referred to as the City Gate price. This is the price at which the natural gas is transferred from an interstate pipeline into the distribution network of a local natural gas distribution company, such as Liberty Utilities, the largest of the New Hampshire natural gas companies. The City Gate price is the local wholesale price and reflects the price of natural gas plus the transportation charges involved in getting it from some location to the city gate. The difference between the Henry Hub price and the city gate price is known in natural gas geekspeak as the “basis differential”.  This basis differential does fluctuate, especially in the cold winter months when we are using a lot of natural gas for heating and generating electricity and there is limited natural gas pipeline capacity to get the gas to us.  Because of heavy demand in the winter for pipeline capacity, the basis differential rises.  

Here in New England there are several city gates: the most important for New Hampshire is the Dracut City Gate, where Liberty Utilities picks up natural gas from the Tennessee Gas Pipeline (see End of the Line for a discussion of the local natural gas pipelines of interest to us here in NH). The most commonly discussed and quoted city gate price in New England is that of the Algonquin City Gate in Boston where the Boston gas distribution company, Nstar, taps into the end of the Algonquin Gas Transmission pipeline which brings gas into Boston. Even though there are price variations between the various local city gates, the Alqonquin city gate price is a useful proxy for the local New England wholesale price of natural gas. The figure below shows the average monthly Henry Hub prices and the Boston City Gate prices since 2000. A few key points are noted from this chart.

  • Natural gas prices have fluctuated significantly over the past 13 years, with big spikes in 2005 and 2008.
  • After the run up in natural prices in 2008, natural gas fracking kicked into high gear, supply increased dramatically, and the Henry Hub price dropped to about $ 2/MMBtu. Prices have steadily increased since then and are now of the order of $ 4/MMBtu.
  •  The Algonquin City Gate price is always higher than the Henry Hub price, reflecting the cost of transporting natural gas to New England.
  • The difference between the City Gate and Henry Hub prices, the basis differential, varies significantly over time, with spikes in the high-demand winter months and then dropping off to lower levels in the summer months.
  • The average monthly basis differential over this period was $ 2.93/MMBtu: during some periods it rose as high as $ 6/MMBtu on a monthly basis.



 Data Source: EIA
But now it starts to get complicated. On top of the different city gates locations, there are different prices at the city gates.  There is the spot price, which is the price paid for the purchase of natural gas to be delivered the following day, and then there is the bid week price, which is the price paid for the purchase of gas for the upcoming month.  The term “bid week” comes from companies bidding for next month’s gas during the last week of the present month. The Energy Information Agency (EIA) recently published an interesting chart that compares the bid week and spot prices at Algonquin City Gate in Boston.



Source: EIA
Important to note is that the bid week prices had been reasonably steady, moving between $ 5 to $ 10/MMBtu, since the winter of 2011: however, this past winter these prices increased almost sevenfold to about $ 35/MMBtu. More noticeable are the wild swings in the spot prices this past winter, when they rose as high as $ 80/MMBtu! Those high spot prices had profound effects on electricity prices on those days. For the most part, the local natural gas distribution companies do not purchase large amounts of natural gas on the spot market, but instead use a variety of tools to protect their customers from these large fluctuations.

These include buying natural gas throughout the lower demand summer months, when prices are generally lower, and storing the gas in underground storage caverns in other parts of the country. The natural gas utilities also have some limited local above-ground storage for compressed natural gas. Some local distribution companies (LDCs) also store liquefied propane gas  on-hand to mitigate any short term natural gas shortages.

Besides buying cheap gas in the summer and storing it, the LDCs also use various hedging techniques to protect consumers from wild price fluctuations. Hedging is an interesting and an extraordinary useful financial tool that many organizations use to protect themselves and their customers from commodity price variations. Let’s consider the hedging approaches that an LDC might use to protect their customers from fluctuations in natural gas prices, especially in the cold winter months. There are two main approaches.

The first is the purchase of a certain amount of natural gas for delivery sometime in the future, known as a forward contract. To do this well, the LDC needs to forecast how much gas they will purchase in the cold winter months when there are pipeline constraints and prices climb. The challenge is knowing how much gas to purchase: if they purchase too much, they have to sell the extra; if they purchase too little, they will then be compelled to purchase their shortfall on the spot market which could be very expensive. The amount of natural gas required is very dependent on the winter temperatures and we are all aware of the challenges associated with long-term forecasting of weather conditions. Moreover, there is also a cost associated with locking in a price today for a natural gas that will only be delivered in the future, so invariably  the forward price is higher than today’s spot price.

Another way to hedge future natural gas purchases is to buy and sell financial instruments whose value rises and falls with that of the underlying commodity. These instruments include financial derivatives, such as futures and options. (They are called derivatives because their value rises and falls with that of the commodity from which they are derived.) Consider, for example, if I was a NH LDC and I wanted to lock in a price, say $ 7/MMBtu, for a certain amount of a natural gas price to be delivered in December. Because I am looking to purchase natural gas in the future, I will sell today an equivalent natural gas futures contract today which obligates me to deliver natural gas in December at $ 7/MMBtu. So if we get to December and the spot price of natural gas in December is $ 10/MMBtu I would be paying $ 3/MMBtu more than I wanted to pay in July. However, the value of the futures contract I sold in July to deliver natural gas at $7/MMBtu would have dropped by ~$ 3/MMBtu, and  I can now purchase it back at a lower price. The overall result is that I would have lost money on the rise in spot price of the natural gas but I made money by selling the financial derivative, the futures contract,  high and buying it back low . The money lost on the increase in natural gas price should closely match the money made on the sale and then the repurchase of the derivative, so I should be essentially flat in terms of my price exposure. In other words I am hedged.

Should the opposite happen and the price of natural gas falls between now and December, I would make money because I would be buying the commodity at a lower price but I would lose an equivalent amount of money on the derivative which has risen in price. Again my exposure is flat – and again I am hedged. Because these hedging transactions are a form of insurance, there is a cost, like the cost of a forward contract, associated with purchasing this insurance. NH natural gas ratepayers pay for this insurance through their natural gas rate.  It is important to note that hedging programs do not lower the cost of natural gas - they just serve to lock in prices for future purchases and partially protect rate payers from spiking natural gas prices.

All of this is important because Liberty Utilities, the largest NH natural gas LDC, has recently submitted a proposal to the NH Public Utilities Commission (PUC) to move away from hedging natural gas prices through financial instruments such as options, to simpler forward contracts that involve the purchase of a fixed amount of gas for a specified price in the winter months. The reason for this change is that the older financial derivative hedging program was based on the Henry Hub price where price volatility is now a lot lower (see the first graph). However, these hedging programs did not protect rate payers from volatility in the basis differential, which can be enormous during the winter months.  The newly proposed forward contract program involves delivery of natural gas to the City Gate and therefore includes the basis differential. From my perspective, this appears to be a sound change in the hedging program. However, I did note that between these forward purchase contracts and the use of local and underground storage, Liberty Utilities believes it would be locking in the price of about 57% of natural gas used in the three cold winter months of December, January, and February. This percentage seems low and I would have thought that the natural gas utilities might have done a better job of hedging a larger percentage of their forecasted use. This could be an interesting topic for a future blog.

Returning to City Gate natural gas prices, remember that City Gate is a wholesale price and it is not what we pay for natural gas delivered to our homes: we pay the retail rate, which is substantially higher than the wholesale price.

For NH residents, natural gas is a regulated commodity so prices are set by the NH PUC based on information submitted by the LDCs. Commercial and industrial natural gas customers are able to purchase natural gas from competitive suppliers but this option is not available for natural gas supplied to NH residents. Price setting for natural gas is done twice per year so there are summer and winter prices. However, the utilities have the ability to increase their prices up or down from their approved summer or winter prices, depending on demand and natural gas prices. These interim prices changes cannot be more than 25% of the approved winter or summer rates.

As I noted in Jumping Jack Gas, there are three main components to NH natural gas bills: for clarification, I have included an example of a residential natural gas bill below. There is: 1) a minimum service or meter charge; 2) a distribution charge; and 3) a fuel charge. The minimum service and distribution charges cover the cost of distribution of the natural gas by the local distribution company. As a regulated utility, the LDC can recover all costs associated with distribution as well as earn a return on the capital they have invested into the distribution pipeline infrastructure. On the other hand, the LDC cannot earn a return on the natural gas they supply. They can only pass on the costs associated with the gas they purchase on a dollar-for-dollar basis. These include the wholesale price of the natural gas (the City Gate price), any associated delivery and pipeline charges, and the costs associated with any program aimed at buffering customers from natural gas price fluctuations. These include the costs of hedging and storage programs.



So what are the utilities charging for natural gas once all the costs are factored in? Well, that depends on what utility you are talking about (see Pipeline for a discussion of the two NH natural gas LDCs). The two natural gas distribution companies operating in New Hampshire each have different cost and overhead structures so their rates are somewhat different, as I show in the table below and which compares recent summer and winter rates. The largest of the two, Liberty Utilities, has lower costs, most likely because they have a larger customer base over which to distribute their fixed costs. The distribution costs for Liberty are of the order of $ 3/MMBtu, whereas those for Unitil are almost double that: if you are living in a Unitil service area, you are bearing the brunt of their smaller customer base and higher costs. (Note that natural gas rates for customers are normally quoted as $/therm but I have converted them to $/MMBtu by simply multiplying by 10. See Jumping Jack Gas  for natural gas units and conversion factors.)
  


When we reflect on all these different prices, it is clear that when we discuss natural gas prices in NH we should always start with the question; “What natural gas price are we talking about?” This discussion has shown that there are three key prices: (1) the Henry Hub price, which is the commodity price for natural gas in the US markets; (2) the City Gate price, which is the local wholesale price and which reflects the costs of transporting the natural gas to New England. The City Gate price is, on average, about $ 3/MMBtu higher than the wholesale price but in the cold winter months this price differential can rocket up. (3) Finally, the retail price is what NH residents pay to get natural gas delivered to their homes. This reflects the wholesale cost of gas plus costs associated with gas storage and hedging programs to buffer residents from big swings in prices. The retail cost also includes costs associated with the distribution the natural gas through the LDC distribution network. These distribution costs are of the order of $ 3/MMBtu for Liberty Utilities and $ 6/MMBtu for Unitil.

I trust that I have been able to guide you through the maze of natural gas pricing and that you have a better appreciation of the challenges and complications faced by the NH regulators and LDC as they work to set prices and protect NH natural gas customers from wild swings in natural gas prices. There is always a price to be paid for such programs, but my assessment is that the price* appears to be a fair one.

Until next time, turn up the temperature on your air conditioner by a degree or two and remember to turn off the lights when you leave the room.

Mike Mooiman
Franklin Pierce University

(*The Price – A great tune by The Steeldrivers. Kinda sorta bluegrass music but it does rock. These guys are out of Nashville and received several Grammy nominations a few years ago for Best Bluegrass Album and Best Country Performance by a Duo or Group. Enjoy The Price) 

Sunday, April 13, 2014

Pipeline* - Local Natural Gas Distribution Companies - Natural Gas in New Hampshire Part 3

In my last post, I finished off by introducing the two local natural gas distribution companies (LDCs) here in New Hampshire that deliver natural gas to residential, commercial, and industrial customers through their distribution networks. As a reminder, I again present the map below  which shows the service areas of these two LDCs.


Source: NHPUC
The first and largest of the NH LDCs, with about 89,000 residential, commercial, and industrial customers as of 2012, is EnergyNorth which does business under the Liberty Utilities umbrella. Liberty Utilities has the franchise for the distribution of natural gas up the Merrimack corridor to the Lakes region—where they tap into a branch of the Tennessee Gas pipeline—and the tiny Berlin “island”, where they draw off the Portland Natural Gas Transmission System Pipeline that crosses the northern part of the state. EnergyNorth was, for many years, a standalone natural gas distribution company, but has recently been through several ownership changes. In 2000, it was acquired by Keyspan. In 2006, National Grid, a UK utility company, acquired Keyspan. National Grid then sold EnergyNorth to Liberty Utilities in 2012. Liberty Utilities is itself part of a much larger, multifaceted energy company, Alqonquin Power and Utilities Corporation. Alqonquin owns hydroelectric, wind, and solar generating facilities, and well as water, natural gas, and electricity distribution businesses in the US and Canada. Alqonquin Power and Utilities is headquartered in Oakville, Ontario, and is listed on the Toronto Stock Exchange. Liberty Utilities also has a smaller business distributing electricity to about 43,000 customers in the west and south regions of NH.

The other natural gas LDC is Northern Utilities, which operates under the Unitil name. This is a smaller natural gas and electricity distribution company with operations in Maine, NH, and Massachusetts. In NH, their gas distribution business is limited to the sea-coast area where they draw of the Granite State Gas Transmission pipeline which runs up the coast to Portland, Maine.   In 2012, they had about 30,000 natural gas customers. Northern Utilities Company has also been through many ownership changes. It was purchased by Bay State Gas in 1979, which  merged with NiSource in 1999. NiSource then merged with the Columbia Energy Group in 2000 and, in 2008, Northern Utilities was purchased by Unitil. Like Liberty Utilities, Unitil is also in the electricity distribution business in NH. Unitil is a publically traded corporation listed on the NYSE and is headquartered in Hampton, NH.

There are two aspects to the business of the LDCs. The first is creating and operating the natural gas distribution pipeline and the other is providing the gas that the customer uses. This is the reason that NH natural gas users are charged separately for natural gas distribution services and for the natural gas commodity itself (see Jumping Jack Gas for a typical breakout of a NH natural gas bill).  Establishing and operating a gas distribution network is a complicated, expensive,  and highly specialized business so these utilities have the sole right to distribute natural gas in a specified area - a monopoly - on condition that it is done cost-effectively, safely, and that the service is reliable. As a consequence of the monopoly awarded to these companies, they are tightly regulated by the New Hampshire Public Utilities Commission. (For a primer on public utilities, see What’s It All About, Alfie?)

In NH, the natural gas business is partially deregulated. Only the large industrial and commercial customers can choose their natural gas supplier from competitive suppliers. Residential users have no choice and are obligated to purchase their natural gas from their local distribution company. The LDCs therefore distribute natural gas supplied by others in the case of commercial industrial customers or supplied directly by themselves directly for residential customers.

Operating a natural gas distribution company is a challenging business. As we were reminded again by the gas explosion in New York last month that killed eight people and leveled two buildings, handling, transporting, and safely delivering a combustible fuel takes special technology and unique precautions. When the pipelines leak and the leaks go undetected or unreported, the consequences can be disastrous. The LDCs have a safety-first approach and are very concerned about running a safe distribution system. They react rapidly to reports of natural gas leaks. We, as citizens, also bear some responsibility for natural gas safety and we should promptly report leaks when we smell that distinctive natural gas smell. All excavation projects, including simple home projects like planting trees and shrubs, should be first cleared by a call to the Dig Safe hotline at 811 so that they can come out and mark where your utility lines run. Nothing quite spoils a gardening or home construction project like puncturing a natural gas line: you really don’t want to be that guy who caused the whole neighborhood to evacuate on a Sunday morning! 


Source: Flickr - Eugene Peretz

One of the prevailing safety issues is that the original gas distribution piping was made of unprotected cast iron or bare steel buried underground. After years of underground exposure, these pipelines slowly corrode and, in areas where soil moisture is high or the conditions are highly corrosive, corrosion can be severe and leaks can occur. The picture below shows a piece of highly corroded pipe removed from a natural gas distribution network in NH. The LDCs have active programs in place to replace steel pipe with newer and safer high tech plastic piping, but this is an expensive endeavor with costs of the order of $1.5 million per mile. Over the years, the utilities have replaced a great deal of their networks with plastic distribution pipelines. The latest pipeline report indicates that only 155 miles (8.2%) of the 1875 miles of piping in NH is still made of iron. Compare this to NYC, where 60% of distribution mains are still made of cast iron or bare steel and where some of the lines are over 100 years old.


Corroded Natural Gas Pipeline from Nashua, NH Area
Source: NHPUC Filing

These LDCs are an important component of the business infrastructure for NH and, like all other businesses, they are looking to grow and to earn a return on their investment. However, they face some unique challenges. From my research and discussions with some of the LDCs and other folks who have been in the natural gas business for a long time, I got an improved understanding and appreciation for their business and challenges. Here are some of the interesting things I have learned:

  • LDCs make their money from the distribution of natural gas and not from the sale of gas. The natural gas is passed through to their customers on a dollar-for-dollar basis. They are not allowed to mark up the price of natural gas that they purchase and resell. In the case of commercial and industrial customers, they simply transport gas provided by a competitive supplier.
  • Because the LDCs are regulated utilities with a monopoly in their service area, any rate changes to their services need to be approved by the regulators at the NH Public Utilities Commission. 
  • In the rate-setting process, several factors are taken into account, the key one being the investment the LDCs have made in distribution equipment and facilities (pipelines, compressor stations, trucks, etc.) as well as the working capital used to operate their business. These investments are collectively known as the rate base. Expenses such as payroll, administration, and taxes are also taken into account. Because LDCs are for-profit business, they are allowed to earn a return on their distribution services, however, the rate of return is capped by the regulators, and is typically in the range of 9 to 10% on the equity invested.
  • Rate-setting is a complicated business and rate cases presented by utilities are expensive and lengthy endeavors requiring a great deal of review and analysis by both the LDC and the regulators.
  • Growing the natural gas distribution business is expensive and challenging. The reasons are complex, but an important aspect is that within the networks, the LDCs have already been very successful in signing up natural gas customers. In their service areas, which is considered to be within 100 ft of natural gas main, the LDCs have already signed up about 80% of potential customers. This significantly limits potential growth in their customer base from within their existing distribution network. Growth needs to come from expanding the network.
  • At the same time as the natural gas utilities are trying to grow their businesses, there is a negative impact on natural gas usage due to energy-efficiency measures  in homes and the “natural” turnover and replacement of aging heating units, such as dryers and stoves, to more efficient units.

As public utilities, the LDCs are required to submit annual reports to the NH Public Utilities Commission. These reports make for compelling reading. Here are some interesting details that I gleaned from an examination of the 2012 annual reports (2013 reports are not yet available):

  • These are capital-intensive business with profitabilities of the order of 5%.
  • Revenues per customer are ~$900 per year and net income per customer is only about $50/year, which is not a great deal.
  • The bulk of their costs are associated with the purchase of natural gas (about 60% of their overall expenses).
  • Other costs include typical operations and maintenance costs, depreciation, administration and debt service expenses.
  • The LDCs keep a small supply of liquefied natural gas at storage facilities on hand to assist with supply shortages. Some will even use propane when natural gas is in short supply and some LDCs have even purchased storage capacity at underground storage locations located in other parts of the US to ensure gas supply during periods of high demand.  

A question often asked is why the natural gas utility cannot provide natural gas to your home. The main reason is that there may not be a natural gas main pipeline nearby. The service area for a natural gas company typically lies within 100 ft of a mainline: anything further becomes too expensive. Expansion of service area by the laying down of new distribution piping is expensive and consideration must be given to the costs of pipeline extensions, housing density, and the probability of signing up new customers. Moreover, regulators are very sensitive to the “socialization” of expansion plans so they do not want network expansion plans funded by rate increases for existing customers. New pipelines, which cost about $1 million per mile, have to be paid by new customers. As noted earlier, the income per natural gas customer per year is low so capital recovery and return on investment requires a very long period. It is for this reason that expansion in natural gas service areas is a slow, measured, and carefully evaluated process.


In my next post, I will take a closer look at retail natural gas pricing in New Hampshire, which turns out to be a fairly complicated matter.

In the meantime, remember to turn off the lights before you leave the room and call Dig Safe at 811 before starting to dig.

Mike Mooiman
Franklin Pierce University
mooimanm@franklinpierce.edu






[*Pipeline – A great 1960’s surf music instrumental by the Chantays. I have always have loved the way this tune kicks off with that distinctive riff. You just know there are good things to come. Here is Pipeline, covered by Stevie Ray Vaughn and surf guitar god, Dick Dale.]