Hydropower Technical Work Group Peer Review Contribution · The three hydropower plants at Sault...

Hydropower Technical Work Group Peer Review Contribution

Electricity Price Outlook for Upper Great Lakes

Hydroelectric Facilities

A Study in support of the International Upper Great Lakes Study

January 20, 2011

Prepared by the International Upper Great Lakes Study Team

Table of Contents

Page 1.0 Purpose and Scope 4 2.0 Relationships between Levels and Flows and Energy Production 6 3.0 Concerns about High and Low Lake Levels and Outflows 7 4.0 Future Demand for Electricity 7 5.0 The Need for Future Wholesale Electricity Price Forecasts 8 6.0 Institutional Arrangements Governing Plant Operations and Water Allocations 9 7.0 How Costs and Prices are Determined 10 8.0 Study Methods and their Rationale 10 9.0 How Synapse Prices will be used in Decision Making 14 10.0 Findings and Conclusions 18

Appendix Appendix A – Maps of Hydropower Plants and Relevant Hydrologic Information Figure 1: Hydropower Plants in the St. Marys River Figure 2: Hydropower Plants in the Niagara River and Plants Using Welland Canal Water Figure 3: Historical Monthly Mean Lake Superior Outflows, m3/s Figure 4: Historical Monthly Mean Lake Erie Outflows, m3/s Appendix B – Flow Chart Figure 1: Electricity Price Outlook Component of the International Upper Great Lakes Study Appendix C – Electricity Price Outlook for Upper Great Lakes Hydroelectric Facilities, Forecast for the International Joint Commission, Synapse Energy Economics, Inc., Final Report January 19, 2011.

4

1.0 Purpose and Scope The main objective of the current International Upper Great Lakes Study (IUGLS) is to investigate possible improvements to the regulation of the outflows of Lake Superior to better meet the contemporary needs of all the water-dependent interests in the Great Lakes region. Outflow regulation is carried out by adjusting the flows of the structures in the St. Marys River at Sault Ste. Marie, Ontario and Michigan, including the hydropower plants. A parallel component of the Study is the development of an adaptive management plan that identifies areas of vulnerability affecting hydropower operations, and possible remedial measures designed to eliminate or alleviate the risk. As part of the IUGLS study, key aspects of the various inquiries have been selected for peer review because they are considered critical to decisions made about selecting a new regulation plan. The Synapse energy price study under peer review will be used along with other information to rank alternative rule sets for regulating releases from Lake Superior. This companion paper describes how the Synapse information will be used by decision makers so that peer reviewers can judge the quality of the study and results for their intended use. The water levels and outflows of the Great Lakes are constantly changing in response to the hydroclimatic, hydraulic and meteorological conditions of the basin. These changes affect the Great Lakes interests including the hydropower interest. At the direction of the International Joint Commission (IJC) the IUGLS Board is investigating possible changes to the present method of regulating the outflows of Lake Superior to better meet the contemporary needs of the interests and also taking into consideration the potential effects of climate change. Since water level management in the Upper Great Lakes is limited with outflows being controlled by structures within the St. Mary River, the furthest upstream connecting channel, additional structural measures are also being investigated as part of the integrated Great Lakes system-wide water management study, particularly considering extreme hydrometeorological conditions. Changing the present method of regulating the outflows of Lake Superior, or implementing other structural measures can be expected to affect hydropower generation and revenue. The Study Board has decided that new regulation rules must meet the requirements of the Boundary Waters Treaty of 1909 and should provide the greatest benefits to several sectors that are affected by regulation, including commercial navigation, the natural environment, coastal residents, municipal and industrial water users, recreational boaters and tourists, and hydropower users. The treaty requirements are open to some interpretation, but generally require that no structure (including the works in question here) may cause any significant loss of any water use in practice when the treaty was signed, and that some uses have precedence over others. This precedence is not absolute, as it is in appropriation law, where junior users lose all water rights in a drought before senior users lose any; its practical implication for the Study Board is that it will not recommend regulation alternatives that significantly and negatively affected domestic water users, shippers or the hydropower industry.

5

The Synapse results will be used as one measure of whether the hydropower sector would suffer under the new rules, along operational criteria that track water conditions that make it difficult to produce hydropower (these constraints are discussed in this report in sections 3 and 5, below). The primary use for the Synapse results will be to support the Board’s assessment of whether new regulation rules provide a benefit to society. The IJC accepted the advice of economic advisors to the 2000-2005 International Lake Ontario-St. Lawrence River Study (ILOSLRS) that the marginal price of electricity is the best measure of the incremental gain or loss of societal value provided by hydropower generation, and that principle has been applied by the IUGLS Board. A description of how plans will be ranked using benefit estimates based on the Synapse prices will be discussed later in this paper. For the hydropower interest, the Upper Great Lakes Study requires knowledge of the relationships between water level/flow and hydropower generation, the expected energy and revenue for the various water management options and climate scenarios. It is one of the essential tasks to evaluate the merits and feasibility of water management options. Electricity price outlook is also used by hydropower operators for making decisions on short and long-term capital investments for their hydro infrastructure and operating practices, as well as for normal maintenance and longer term rehabilitation and replacement of turbines and other associated infrastructure. The Upper Great Lakes Study has engaged an independent consultant to conduct an outlook of electricity pricing for the Great Lakes hydropower facilities and a report for this purpose entitled “Electricity Price Outlook for Upper Great Lakes Hydroelectric Facilities, January 19, 2011” has been prepared and is included as Appendix C to this paper. The purpose of the peer review is to assess the approach taken by the consultant, and evaluate the appropriateness of the assumptions and method used and the validity of the study findings. The hydropower plants included in the electricity price outlook study are those situated at the outlet of Lake Superior in the St. Marys River (Figure 1 in Appendix A), and at the outlet of Lake Erie in the Niagara River and those that use the water from the Welland Canal (Figure 2 in Appendix A). The three hydropower plants at Sault Ste. Marie, Ontario and Michigan (Cloverland, Brookfield’s Clergue, and US Government) have a total generating capacity of 115 MW and diversion capacity of about 2400 m3/s which is more than the average St. Marys River flow of 2120 m3/s. The plants in the Niagara River (Beck 1, Beck 2 and Moses including pump-generating stations) have a total generating capacity of about 5100 MW and total diversion capacity of about 4670 m3/s given the present tunnel and power canal configuration and will be increased to 5130 m3/s when the Niagara tunnel project is completed in 2013. Several other relatively smaller plants (DeCew Falls, Heywood and Welland Canal Weirs 1-3) using the Welland Canal water have a combined capacity of 180 MW and 540 m3/s. For comparison purposes, the average Lake Erie outflow is about 5900 m3/s. Except for the Niagara tunnel project, the existing flow capacities for the hydropower plants are not likely to be expanded in the foreseeable future. The only increases in production will come from marginal improvements in turbine efficiencies, and from small changes in the regulation plans – to the extent feasible, without harming other interests. One of the ways of increasing

6

hydropower production is to emphasize peaking capacity and production – producing maximum electricity during periods of greatest demand – during cold and hot weather spells.

2.0 Relationships between Levels and Flows and Energy Production The amount of hydropower that can be generated is directly proportional to the rate of flow through the turbine that drives the generator, and operating head which is the water level difference between the plant’s forebay and its tailrace. Hence, high flow and head generate more power and reduction in either or both decreases power generation. Today, large modern turbines operate typically at mechanical efficiencies greater than 90%. The amount of water a hydropower plant can divert is a function of several factors including lake level and river flow, the plant’s discharge and generating capacity, and the hydraulic conditions of the river and power canal. For the hydropower plants in the IUGLS, the international institutional arrangements governing hydropower plant operations, called Orders of Approval, which were negotiated amongst the United States, Canada and the International Joint Commission, codify the physical capacity relationships together with the needs and interests of the other water-dependent users and interests (navigation, municipal water supply, riparians, irrigation, recreational boaters and environment). The operating heads at the three plants in the St. Marys River are about six metres. Hence, they can be classified as low head hydropower plants (defined as having less than 30 m head) generating a relatively small amount of power (kilowatts) for each unit of water diverted (cubic metre). They have, however, the advantage of having Lake Superior outflow as the source and thus have a fairly dependable supply of water. There are in the upper Michigan and Wisconsin region power plants using fossil fuel having larger generating capacity, however the hydropower capacity in the St. Marys River constitutes a good portion of the total generating capacity of the region. With over 5000 MW capacity, the plants using the Lake Erie outflow for electricity generation constitute a significant and dependable source of power to the southern Ontario and western New York State power grids. Their operating heads of about 90 metres put these plants in the medium head category using the strict definition (30 to 300 metres). The nearest hydropower complex having large generating capacity are the Saunders and Moses stations in the international reach of the St. Lawrence River each at about 1000 MW. The relationship between energy generation and revenue is highly complex and depends on the following factors: demand, power generation mix, regulations, etc. These factors and their longer term outlooks are described in a contextual narrative written for the IUGLS by Drs. Robert Sinclair and David Patton of Potomac Economics. Synapse Energy Economics, Inc. has examined recent and current electricity prices and developed an outlook for future wholesale electricity prices relevant to the upper Great Lakes hydropower facilities (Appendix C) to which this paper is a preamble.

7

3.0 Concerns about High and Low Lake Levels and Outflows A review of the data for the past century shows that the Great Lakes have experienced episodes of both high and low water levels – the result of naturally fluctuating water supplies to the Great Lakes basin. Lake Superior outflow regulation (and Lake Ontario outflow regulation which was the subject of the ILOSLRS mentioned previously) can moderate to a small extent the very high and low lake levels, but the variations in water supplies remain a major factor affecting lake levels and flows. While high levels and flows enhance power generation, they pose operating problems such as frequent use of spillways, channel and canal erosion concerns, and structural integrity for some hydropower infrastructure. Low levels and flows reduce power generation and these situations can be more serious when they have an impact on a plant’s economic viability. The most recent well-above average level and flow episode on the upper Great Lakes (Superior, Michigan, Huron and Erie) occurred in 1985-86 and since then, the basin has experienced generally at or below average water supply conditions. The current below-average water level condition is considered to have started in about 1998, although since then there have been short intervals with near average levels. In Appendix A, Figures 3 and 4, respectively, the historical monthly mean Lake Superior and Erie outflows is shown. Well-above average Lake Superior outflows occurred in 1985 and 1986 which were then followed by a rapid decrease in outflows reflecting the rapid decline in the lake levels in 1987 and particularly 1988. Lake Erie, which receives the bulk of its water supplies from the upper lakes, also experienced high levels in 1986 and 1987 and, like the upper lakes, saw its level dropping rapidly in 1988.

4.0 Future Demand for Electricity

Electricity demand closely tracks growth in economic activity. A growing economy consumes more electricity to meet needs from manufacturing to transportation and household consumption practices. The law of demand and supply mainly dictates the price of electricity to be paid by the users. Weather is also a factor as unusually hot and cold weather can result in increased electricity consumption for cooling and heating, respectively. In Ontario, electricity demand has declined since reaching a peak in 2005. The most recent publication on this subject is that made by the Ontario Ministry of Energy in November 2010 in its “Ontario’s Long-Term Energy Plan – Building Our Clean Energy Future”: http://www.mei.gov.on.ca/en/pdf/MEI_LTEP_en.pdf . According to the plan, electricity demand recovered slowly in 2010 after the global economic recession. Future demand will depend on a number of factors including: the speed of Ontario’s economic recovery, population and household growth, greater use of electronics in appliances and home entertainment systems, the pace of the recovery of large, energy-intensive industry and the composition of the economy (e.g., a shift to more high-tech and service jobs). Demand will also be impacted by the success of conservation efforts and choice of fuel for public transit vehicles. The plan places emphasis on maintaining a clean, modern and reliable electricity system by retiring the

http://www.mei.gov.on.ca/en/pdf/MEI_LTEP_en.pdf

8

air-polluting, coal-burning plants and promoting renewable energy including hydropower, solar and wind power. Ontario’s plan outlines three potential scenarios for electricity demand: low growth, medium growth and high growth for the years 2010-2030. On pricing, it expects that for the next 10 years demand is expected to recover from the recent recession and then stay relatively flat as conservation efforts and an evolving economy change Ontario’s energy need. It also estimated that for the general household consumers, residential prices over the next 20 years are expected to increase by about 3.5 percent per year. In the United States, the U.S. Energy Information Administration (EIA) makes projections of energy consumption by fuel including hydropower: http://www.eia.doe.gov/oiaf/forecasting.html. In its most recent analysis (available online), there were sharp reductions but of short duration (2008 and 2009) in energy consumption for the liquids sector (oil and petroleum) and coal. Natural gas consumption during the recent economic downturn seems not to be affected and this could be due to the fact that natural gas is essential for heating purposes. Similarly, hydropower consumption preceding and during the economic downturn has remained fairly constant. The EIA projections show consumption for all energy sectors is expected to steadily increase through 2035 while that for hydropower would remain fairly steady. No new major hydropower developments are expected in the near future. The rate of increase for nuclear energy is not as large as that related to fossil fuel, while non-hydro renewables are projected to increase fairly rapidly.

5.0 The Need for Future Wholesale Electricity Price Forecasts As with other major studies of the Great Lakes water levels and outflows, the IUGLS is a highly integrated multi-disciplinary study which examines and evaluates the inter-relationships between water levels and flows and the Great Lakes interests – hydropower, navigation, coastal zone, ecosystems, water uses, boating and tourism. Central to all these are the development and testing of Lake Superior outflow regulation plans and other structural measures and the determination of the impacts on the interests under the current climate regime and regimes generated by global climate change models. For analysis, a series of water level and outflow hydrographs are generated corresponding to the water management options under different water supply scenarios (including plausible future climate change scenarios). The information is next evaluated using integrated analytical models such as the ‘Shared Vision Model (SVM)’ (see the Strategy Document entitled “Socio-Economic Sector Evaluations of Lake Superior Regulation Plans for the International Upper Great Lakes Levels Study” dated July 14, 2009). The SVM compares the levels and flows generated by alternative regulation plans considering performance indicators and coping zones determined to assess interest impacts including gain or loss of shore land, wetlands, energy generation revenue, improvement or degradation for a wide range of environmental indicators. For the hydropower interest, performance indicators include energy generated, peak capacity and revenue; while coping zones refer to different levels and flows and other physical factors having varying degrees of impacts on hydropower operations.

http://www.eia.doe.gov/oiaf/forecasting.html

9

Therefore, knowledge of future electricity prices is essential in order to credibly evaluate the beneficial and adverse impacts of water management options on the hydropower interest. Short-term, i.e., a 2-year ahead, and long term, i.e., 30-year ahead, electricity price forecasts are desired for the hydropower plants of the upper Great Lakes, to the extent practicable. The results thus obtained are a prerequisite to the determination of the relative performance and feasibility of alternative regulation options.

6.0 Institutional Arrangements Governing Plant Operations and Water Allocations The use of the Lake Superior and Lake Erie outflow discharges for hydropower purposes is governed by Treaties and special bilateral agreements between Canada and the United States, and by criteria and requirements of the IJC and its operating Boards of Control. For example, the Lake Superior outflow regulation plan specifies the monthly mean outflows and hydropower allocations, taking into consideration the hydrologic conditions on the upper Great Lakes system and the needs of the Great Lakes interests. After deducting the amounts required for domestic and industrial uses, the St. Marys River Rapids, and for navigation lockage, the remaining water may be divided equally between Canada and the United States for hydropower purposes. Since the sum of these priority uses is relatively very small, the water diverted by the St. Marys River hydropower plants typically represents most the of the total river flow.

When the amount of water available for power purposes exceeds total plant capacity, the excess is released at the St. Marys River Compensating Works. Given their monthly water allocations, the hydropower operators can vary the flow of water at the plant, within limits allowed by the IJC regulations, to maximize use of the water for power purposes. Shifting generation within a 24-hour period to better match load and prices is called “peaking operations”. Shifting generation within a week (higher flows on weekdays and lower flows on weekends) is called “ponding operations”. The Niagara River Treaty of 1950 objective is to preserve and enhance the scenic beauty of Niagara Falls while providing for the most beneficial use of the river waters for hydropower generation. The Treaty requires that during the daylight hours for the months of April through October the flow over Niagara Falls should be no less than 2832 m3/s; and at night the minimum Falls flow is 1416 m3/s. For the months of November to March, the minimum Falls flow is 1416 m3/s. All waters (the sum of Niagara River flow and Welland Canal diversion) in excess of those required for domestic and sanitary purposes, for the services of canals and locks and for Niagara Falls may be diverted for hydropower generation. Given the fluctuations of the Lake Erie levels and outflows, there are occasions when water diversion for power purposes is reduced below plant capacity at times of low river flow in order to maintain the Treaty minimum flow over the Falls. There are also occasions when available water for power purposes exceeds diversion capacity and the excess is spilled over Niagara Falls. Diversion

10

capacity can be reduced as a result of a lack of generating units, or due to ice jams and ice grounding in the Niagara River at water intakes.

7.0 How Costs and Prices are Determined Electricity production costs can be divided into two categories: fixed and variable. Fixed costs represent sunk costs that are incurred regardless of how much electricity is generated and these include initial construction costs and fixed operating and maintenance expenses. Variable costs are typically fuel and other consumables and additional variable operating and maintenance costs incurred because of power production. Under traditional utility regulation, via public utility commissions, the price to the customer is set to give a fair rate of return on the investment costs and to cover the variable and fixed operating costs. Over the last decade or so, some regions have implemented a market-based system for wholesale power production managed by Independent System Operators (ISO). There are generally several service markets managed by an ISO. In such a system, the producers submit bids for various products such as electric energy, capacity and ancillary services. The ISO based on costs and technical requirements decides which producers are called upon and what they receive in payment. The wholesale energy market price is determined by the bids submitted by producers and the level of demand. Although suppliers’ bids to some degree represent their variable costs, the relationship between wholesale market prices and total production costs is not clear cut. Because all suppliers receive the market clearing price, most are paid more than their marginal energy costs. The revenue in excess of the suppliers’ marginal energy costs goes to cover their fixed costs as well. Even when averaged over a year, there may be some times when the market price is more than total production costs and sometimes when it is less—although economists assert that over the long term it all averages out. Ontario does not have location-based marginal pricing. In addition, the Ontario Power Generation’s (OPG) plants associated with the Great Lakes (Beck 1 and 2 at Niagara, DeCew Falls by the Welland Canal, and Saunders in the St. Lawrence River) fall under “rate regulation”. This means OPG goes through a hearing process under the Ontario Energy Board to determine the appropriate rate to cover the OPG’s costs and provide a reasonable rate of return.

8.0 Study Methods and their Rationale In Appendix B, a flow chart is provided showing the steps to develop an outlook of electricity prices, their interconnections with the other tasks of the Upper Great Lakes Study, and where the results feed into the integrated analytical model for the evaluation of water management options.

11

Background Information and Data Analysis

The electricity price forecast study started with a review of the operations of the hydropower plants, their capability and physical factors that can affect diversion and generating capability. A review was also made of the international legal arrangements that govern their operations. The investigator examined the hourly flows and energy generation of the past five years beginning 2005 for the St. Marys River and the major Lake Erie outflow (those on the Niagara River and by The Welland Canal) plants and identifies how they managed their water diversions during the day and week to meet energy demand and at the same time for compliance with international water level and flow requirements. Since electricity price is part of the bigger energy market consisting also of natural gas prices, the latter is also examined as part of the review. There is a very good correlation between monthly peak period electricity price and monthly natural gas price. Electricity usage and prices are often separated into two periods: peak and off-peak representing specific hours during the week. To understand the relationship between peak and off-peak prices, the study focused on the Michigan (MI) Hub which is fairly representative of the pattern throughout the upper Great Lakes. Geographic Scope of Energy Market In the Great Lakes region, New York operates as an independent system operator or NYISO. Michigan is the Midwest Independent Transmission System Operator (MISO). Ontario operates in a more regulated hybrid mode. In regards to the value of the upper Great Lakes hydropower generation, the MISO and NYISO market prices are the most relevant ones since they reflect a relationship between supply and demand and the full marginal cost of energy. For the Canadian hydropower plant on the St. Marys River, the study uses the MISO Ontario interface as the pricing point. It is important to note, however, that the hydropower facilities may not actually be paid the market price for the energy they produce, but rather be paid under the terms of various contracts. To give some context for the forecasts generated in this study, a review was made of some historic and recent price patterns.

Recent Prices Natural gas fired power plants are usually the ones that set wholesale electricity prices during peak load periods in the Midwest and Northeast. There is a close correlation between peak period electricity price and natural gas price. A review of the recent MI hub prices shows that, for the three-year period starting 2005, the peak period electricity prices were hovering about $60 U.S./MWh with short duration (one month) close to $90 in mid-2005 and as low as $40 in the fall of 2006. The price peaked in about mid-2008 close to $100 (gas prices also peaked about the same time) and next fell sharply (as did gas prices) to about $30 by the fall of 2009

12

when both electricity and gas prices reached their lowest point. A small recovery followed and by the end of 2010 it was at about $40. The fluctuation of the gas prices followed about the same pattern as the peak period electricity prices prior to, during, and following the economic downturn. At its peak in the fall of 2005 gas prices were slightly above $13 U.S. per million Btu ($/MBtu). The lowest point was in the fall of 2009 at about $3. A small recovery brought it close to $4 by the end of 2010.

Wholesale Electricity Price Forecast Since there are existing markets that these facilities can sell their electricity to (whether they do or not), the ISO market prices are an appropriate societal valuation to use for their output.1 These prices represent the interplay of numerous economic factors and also have the further advantage of being public. Short-Term Forecasts For the near-term forecast, the electricity market futures are used as the basis for the forecast with appropriate locational adjustments. The two-year (2011-2012) forecast by months shows that prices peak in the months of July and August. For example, in the forecasts for the MI Hub, price would start off at $34.7/MWh (nominal dollars) in January 2011, peak at $37.8 during July and August, then decline to $31.8 by the end of 2011. The January 2012 price is forecast to be $37.0, and the price is expected to peak at $40.3 in July and August before declining to $35.9 by the end of 2012. A similar pattern also shows in the 2-year forecasts for the Ont-Int (Ontario Interface) and the UPM (Michigan’s Upper Peninsula) with slightly different monetary values. Two-year forecasts (2011-2012) are also made for the plants at Niagara and those using the water from the Welland Canal. Like those for the Lake Superior region, the monthly pattern is similar with higher summer and winter prices and lower spring and fall ones. Again, the forecast prices are in nominal dollars reflecting the actual futures prices. For the NY-West Hub, prices are forecast to start at $38.9/MWh at the beginning of 2011, peak at $39.4 in July and August before declining to $35.9 by year-end. For 2012, the cycle is expected to start at $41.5, peak at $41.8 in the summer, and decline to $37.3 in December. Long Term Forecasts For the longer term (to 2040), the EIA (U.S. Energy Information Administration) Annual Energy Outlook 2010 is used as the starting basis, but carbon costs are factored in after 2015 based on analysis of various greenhouse gas regulation possibilities. The further one goes out, the

1 For other benefits and consequences of the Upper Great Lakes operations such as fishing and shoreline erosion, the

economic values are much more difficult to assess. Electricity generation is much simpler because of the existing

market.

13

greater the price uncertainties. The thirty year forecast period was chosen as being useful for the long-term planning of the IJC, although uncertainty increases further in the future. The main factors affecting long-term electricity prices are load growth, fuel prices, generation mix and renewable energy requirements, and greenhouse and other environmental regulations, however, none of these can be accurately predicted. Two long-term (2011-2040) forecasts were made, one with carbon dioxide costs and one without. Forecast prices for the first two years (2011 and 2012) are the same as in the short-term forecasts but now in constant 2010 dollars. Constant dollars are considered to better represent the real changes in prices and the future rate of inflation is unknown. In real terms, electricity prices increase by about 40% over this period without carbon dioxide costs or about 1.2% increase per year. If carbon dioxide costs are included, real prices would more than double with an increase of 135% over the same period – an average growth rate of 3.2%. Using the Ont-Int as an example, price is forecast to start at $30.6/MWh in January 2011 (all in 2010 dollars) and would reach $44.6 by the end of 2040 assuming there would be no carbon dioxide costs. Assuming there would be carbon dioxide costs, the price is forecast to rise to $79.7 in 2040. Uncertainties The primary factors affecting short-term electricity prices are natural gas prices and loads. For the longer term, the major factors are: natural gas prices, loads, generation mix including Renewables and CO2 costs. The Annual Energy Outlook (AEO) by Energy Information Administration (EIA) 2010 figures show the range of natural gas prices associated with several cases that assume different rates of technology development. All of the cases show a near term (next few years) increase from the current value of about $5 per thousand cubic feet (mcf) to slightly above $6 for the slow technology curve and slightly below $6 for the rapid technology curve. Next, these price projections continue to rise but at a sharper rate starting about 2020. There are also two other natural gas price forecasts one by the American Gas Association in 2009 and the more recent one by Black & Veatch in November 2010 all showing steady price increases for the high price and low price scenarios. Renewable generation has little influence in setting market price. However they may affect the energy market price indirectly by displacing other generation. There is great uncertainty about future carbon emission costs. A price on carbon could significantly increase the cost of coal and natural gas generation and affect wholesale electricity prices. It is unknown at this time what path such regulation might take. Hence, the investigator has developed two electricity price forecasts: one with and one without carbon dioxide costs.

14

9.0 How the Synapse Prices will be used in Decision Making The IUGLS Board expects to recommend a new regulation plan for Lake Superior based on its overall assessment of performance under a wide variety of climate and water supplies and economic and environmental conditions. The new plan must perform well under conditions seen in the past, and must perform robustly under plausible conditions beyond the historical range. The Board is developing an adaptive management dimension for the regulation plan, recognizing that future economic, environmental, climate and water supply conditions are all significantly uncertain in the Great Lakes region. The Board has held and will continue to conduct “practice” decision workshops in which the focus is on improving the Board’s understanding of the impacts of regulation and defining the decision framework, including the decision criteria the Board will apply in favoring one plan over another. The Board and its support teams have identified the following decision criteria that depend on the Synapse information:

1. A new plan must not violate the protection provided the hydropower sector by the Boundary Waters Treaty. While difficult to precisely define, the Board’s decision will be based on whether operating constraints are violated more often, more severely and for longer than under the current operating plan, and whether hydropower benefits are reduced to any significant degree. These constraints have been identified in detail through interviews with plant operators and catalogued in a report on the so-called “coping zones” for hydropower.

2. Plans that meet the first requirement will be ranked in part by how much they increase hydropower benefits over the current regulation plan.

The net hydropower benefit is defined as the marginal value of energy produced by the alternative plan minus the marginal value of energy produced by the current regulation plan. In practice, small changes in hydropower production imply small increases or reductions in electricity produced (mostly by gas turbine generators) valued at the marginal price. The net benefit is calculated for each month in the SVM simulation. The SVM is run using water supplies roughly equivalent to the 1900-2008 supplies, a 109 year, 1,308 month evaluation and it will also be run with alternative water supply sequences of the same length and timestep. These supplies will be generated stochastically using sample statistics from the historic record, from Global Climate Model downscaling, from Regional Climate Model generation, and paleontological recreations. Unlike previous studies, the Board does not assume that climate is stationary. The practical implication of that is that rather than favoring plans that perform well just on average under supplies statistically generated from a sample of historic supplies – expected values of energy in particular – the Board will also consider how plans perform under plausible extreme conditions, including much greater and much less water than in the historical sample, and changes in seasonal timing. The Board will not assign precise probabilities to all these supply sequences, but instead will balance three considerations – the plausibility of the

15

supply, the magnitude of the impact, and the cost of avoiding the impact. For example, a new plan might be tested with an extremely dry supply sequence generated stochastically from a sample produced by one downscaling on GCM, and under this plan, hydropower production at the Sault would stop. This was in fact the case when the Board tested a plan (“123”) that had been recommended in a previous IJC study based on historical supplies. Absent consideration of the cost of fixing Plan 123, the combination of significant impact and low probability might have made it difficult to accept or reject a plan that almost always outperformed the current plan. But the problem was an absolute minimum release, sustainable under most climate conditions. But relaxing the minimum flow when Lake Superior levels were very low preserved most of the benefits of Plan 123 while avoiding failure under this one, rare but plausible scenario. The Synapse information will be used in this three consideration assessment of plan performance under expected and extreme conditions. Screening plans using hydropower value estimates Plan formulators are developing new alternatives to the current plan. To screen the dozens of trial alternatives they develop, they simulate water levels and flows under historic water supplies, then plug those into the SVM and evaluate a wide range of economic and environmental benefits as well as hydrologic statistics and statistics on how often the plants have to “cope” with difficult operating conditions. New plans may have a noticeable effect on Lake Superior levels and a pronounced effect on the timing and size of releases from Superior, but do not change the elevations of Lakes Michigan-Huron or Erie by very much both because those levels are more affected by local supplies to and releases from those lakes and because new Superior regulation rules shift the rate of transfer of water from Superior, but over time, not the total amount. The plan formulator will determine whether the new plan provides net benefits on average over the 109-year historical simulation using a variety of energy price assumptions. Figure 1 shows the section of the SVM formulators will use. While it is still under development, this screen capture illustrates the options the formulators (and later the Study Board) will have to evaluate hydropower performance. First, the formulator will be able to compare plans using different water supply scenarios; this will change the estimated energy produced each month by the plan. Once a time series of energy estimates is made for the 1,308 month simulation, the formulator can look at a variety of pricing scenarios, first using the pull down menu to select the Preliminary SVM Prices 2010 (carried over from the ILOSLRS and preserved here mainly for formulators to test new plans compared to plans developed using the old estimates); Ontario market prices (actual prices from 2005 to 2009, provided to demonstrate the variability of prices; and the new Synapse Prices. If the SVM user selects the Synapse prices, additional options are displayed for use. The SVM user can select forecasted prices for years 2025, 2030, 2035 or 2040 and whatever the

16

Figure 2 SVM Benefit Estimate Display and Controls

Figure 1 SVM Benefit Estimate Display and Controls

17

choice, may apply or not apply a price premium to reflect the benefit of reduced carbon emissions compared to generating the same energy with gas turbines. In practice, since formulators are interested in net benefits, and because both the alternative and current regulating rules will be evaluated with the same prices, choosing one price set over another will usually just adjust the advantage of one plan over another, not reverse the ranking of plans. There might be exceptions because different prices have different seasonal distributions that one plan or another takes advantage of. If formulators discover such differences, they will screen plans with those price sets, but otherwise will probably use one set, perhaps Synapse 2025 with carbon emission valuation. If Synapse prices are selected, the SVM uses the peak and off peak average price estimates for each calendar month as provided in the Synapse report. The peak and off-peak energy production estimated each month in the SVM is multiplied by the appropriate price to produce energy value estimates for each month, and those are then assembled into statistical representations for the entire run. Formulators will try to produce positive net benefits no matter the price estimates used (the current and alternative plans are evaluated under the same pricing assumption). In general, the difference between plans is small in absolute terms (typically less than $1 million in an average year) and tiny as a percentage of change. Detailed evaluations of promising plans Plan formulators may generate hundreds of trial rule sets as they attempt to improve a wide array of sometimes conflicting objectives simultaneously. The screening process described above is all done in the SVM and can be accomplished in a few minutes. Promising plans will be subjected to a more intense scrutiny to make sure they perform robustly under a variety of possible future climate, water supply, economic and environmental scenarios. Detailed evaluations will include:

Simulation with a dozen or more centuries of water supplies wetter and drier than the 20th century with different monthy distributions (because of warmer winters and the impact on snow pack storage and ice cover)

Simulations with different average hydropower price sets.

Simulations with hydropower prices that vary within the simulation. The last variation is to guard against plans that produce benefits because they produce more energy in months with higher average hydropower prices. Only one plan is being formulated that defines releases as a function of hydropower price; in all other cases, hydropower benefits are the side effect of rules that are functions of calendar, water level and flow triggers and constraints. Prices in the winter go up when winters are cold, and it might be that a plan that tests well with average winter prices would actually waste water during warm winters. To

18

check, formulators plan to do a limited Monte Carlo analysis with a range of January prices throughout the simulation. The price perturbations will be based on the variability seen in the Ontario price data; the Synapse report does not speak to this directly. Adaptive management of the new rule set The Board intends to create a plan to adapt the regulation rules as conditions change. This adaptive management plan will focus on plan drivers whose uncertainty has the biggest effect on relative plan performance. If tests show, for example, that the final recommended plan does not perform well if winter prices fall, then the adaptive management plan would track prices and allow for plan changes to better fit new seasonal price patterns. While plans can always be changed after a long study and political discussion, the intent of the adaptive management plan would be to “tune” the approved plan in small uncontroversial ways when re-simulation with the SVM shows the Study Board would have selected a different plan had they had the new information at hand.

10.0 Findings and Conclusions

1. The amount of water available for the Great Lakes plants is dependent on lake levels and outflows; and for those in the St. Marys River and Niagara River, also subject to criteria and requirements established by Treaty and the IJC. Other factors affecting hydropower generation are equipment efficiency, and hydraulic conditions in the rivers and power canals.

2. Given the current capacities of the hydropower plants, no major expansions are planned for the near future. A slight increase in hydropower generation can be expected from equipment upgrades and better scheduling of the use of available water to meet peak and low electricity demand.

3. The recent economic downturn has resulted in short term reduction (generally 2008 and 2009) in overall energy consumption. Projections for Ontario and the US are for a steady and slow increase in energy consumption for the next 20 years (Ontario projection) and 25 years (US projection).

4. Due to the recent economic downturn and the decline in natural gas prices, the current wholesale electric prices are down significantly from those a few years ago. Expectations are for a gradual price recovery over time.

5. Although the total installed capacity of the three plants in the St. Marys River is only 115 Megawatts, the electricity generated by the plants is a reliable part of the upper lakes region given the source of the water (Lake Superior outflow) that drives these plants.

6. Natural gas prices have been a major factor affecting electricity prices in the recent past and are likely to be so in the future. The high prices and volatility seen in the wholesale gas market in the past are unlikely to recur in the foreseeable future.

7. Assuming that there would be no imposition of prices on emissions of carbon dioxide, electricity prices are forecast to increase by about 40% (in real terms) over the 2011 to 2040 period – an average growth rate of 1.2%. If carbon dioxide costs are included, real

19

prices would more than double with an increase of 135% over the same period – an average growth rate of 3.2%.

8. Changes to the present method of Lake Superior outflow regulation are expected to have marginal impacts on the amount of water available for hydropower purposes for the long term given the present methods of water allocations prescribed by Treaty and IJC requirements.

9. The primary purpose of the Synapse price forecasts is to help rank alternative regulation plans using realistic future prices. Plan rankings are somewhat insensitive to errors in price forecasts for the following reasons:

a. Net benefits drive plan ranking, and because the current and alternative plan are evaluated using the same prices, changes in plan ranking because of changes in prices will only occur if the seasonal distribution of prices is substantially wrong.

b. Plans will be tested using a variety of pricing assumptions. c. Plans that show promise will be evaluated using prices that change in each

calendar month of the simulation according to historic variation seen in actual Ontario prices.

d. Changes in hydropower benefits are relatively small. While average annual differences can amount to a few million dollars per year depending on the prices used, this is far less than one percent of the total value of hydropower energy produced on the Upper Great Lakes.

Appendix A

Figure 3: Lake Superior historical monthly mean outflow.

Figure 4: Lake Erie historical monthly mean outflow.

Historical Monthly Mean Lake Superior Outflow

1000

1500

2000

2500

3000

3500

4000

Jan-0

0

Jan-0

5

Jan-1

0

Jan-1

5

Jan-2

0

Jan-2

5

Jan-3

0

Jan-3

5

Jan-4

0

Jan-4

5

Jan-5

0

Jan-5

5

Jan-6

0

Jan-6

5

Jan-7

0

Jan-7

5

Jan-8

0

Jan-8

5

Jan-9

0

Jan-9

5

Jan-0

0

Jan-0

5

Jan-1

0

Date (Month-Year)

Ou

tflo

w (

m3/s

)

Historical Monthly Mean Lake Erie Outflow

3000

4000

5000

6000

7000

8000

9000

Jan-0

0

Jan-0

5

Jan-1

0

Jan-1

5

Jan-2

0

Jan-2

5

Jan-3

0

Jan-3

5

Jan-4

0

Jan-4

5

Jan-5

0

Jan-5

5

Jan-6

0

Jan-6

5

Jan-7

0

Jan-7

5

Jan-8

0

Jan-8

5

Jan-9

0

Jan-9

5

Jan-0

0

Jan-0

5

Jan-1

0

Date (Month-Year)

Ou

tflo

w (

m3/s

)

Appendix B

Appendix C

Figure 1: Electricity Price Outlook Component of the International Upper Great Lakes Study

Appendix C

Electricity Price Outlook for Upper Great Lakes Hydroelectric Facilities

Forecast for the International Joint Commission Deliverable Two – Final Report January 19, 2011

AUTHORS

David White, Alice Napoleon

This page is intentionally blank.

Table of Contents

1. EXECUTIVE SUMMARY....................................................................................................1

2. HISTORIC AND CURRENT ELECTRICITY GENERATION........................................2

A. ST. MARYS ......................................................................................................................2

B. NIAGARA..........................................................................................................................5

3. HISTORIC AND CURRENT ELECTRICITY PRICES....................................................8

A. MONTHLY PRICES ...........................................................................................................9

B. PERIOD PRICES.............................................................................................................10

C. ELECTRICITY AND NATURAL GAS PRICES ....................................................................11

4. WHOLESALE ELECTRICITY PRICE FORECAST .....................................................12

A. ELECTRICITY FUTURES .................................................................................................12

B. NY WEST SHORT-TERM FORECAST ............................................................................14

C. MICHIGAN SHORT-TERM FORECAST ............................................................................15

D. LONG TERM FORECASTS ..............................................................................................16

5. PEAK PRICE RATIOS .....................................................................................................21

A. HISTORIC PATTERNS ....................................................................................................21

B. POSSIBLE FUTURE PATTERNS......................................................................................22

6. PRICE UNCERTAINTY ....................................................................................................23

A. OVERVIEW.....................................................................................................................23

B. FUEL PRICES.................................................................................................................23

C. RENEWABLES ................................................................................................................26

D. CARBON EMISSION COSTS ...........................................................................................26

E. SUMMARY......................................................................................................................27

7. EMISSIONS IMPACTS.....................................................................................................28

A. MECHANISMS FOR EMISSION CHANGES.......................................................................28

8. APPENDICES ....................................................................................................................29

A. BIBLIOGRAPHY ..............................................................................................................30

B. HYDRO GENERATING STATIONS SUMMARY CHARACTERISTICS..................................32

C. MARGINAL GENERATION AND MARKET PRICES ...........................................................33

D. HISTORIC PRICE PATTERNS .........................................................................................36

E. ENERGY PRICE FORECASTS.........................................................................................38

F. FORECAST UNCERTAINTY.............................................................................................39

G. GHG EMISSIONS REGULATION ....................................................................................40

Acknowledgements

The authors wish to especially thank Syed Moin and Peter Yee for pulling the pieces together after

the sudden departure of the previous technical leader from this project because of other duties. And

also thanks to others who provided technical information and comments for this project: Steve Rose,

David Fay, John Ching, Richard Mueller, Joan Frain, Ernest Maas and Andy Punkari.

Disclaimer

Given the wide scope of this project and the limited time and budget, the authors relied extensively

on existing studies to develop the results presented in this report. However, the authors spent

considerable time reviewing those materials and applying their experience and judgment to produce

the resultant findings.

Abbreviations and Acronyms

Abbreviation

or Acronym

Definition

$ US dollars

AEO Annual Energy Outlook, an annual publication of the US Energy Information Administration

cms Cubic meters per second, a measure of water flow; also represented as m3/s

CAGR Compound Annual Growth Rate

CO2 Carbon dioxide, the most significant greenhouse gas

Constant dollars Monetary value adjusted to remove the effects of general inflation

ECAR East Central Area Reliability Coordination Agreement, a North American Electric Reliability

Council region in the north-central US that covers Michigan in the north to Kentucky and

Virginia (in part) in the south, and from Maryland (in part) in the east to Indiana in the west

EIA US Energy Information Administration

GHG Greenhouse gas(es) contributing to global climate change

HH Henry Hub, the primary market for natural gas in the US, located in Louisiana

IESO Independent Electricity System Operator of Ontario, an ISO

IJC International Joint Commission

ISO Independent System Operator, an entity that acts as an electric system balancing authority

and may oversee and administer wholesale electricity markets

Load End use of power on the electric system

m Meter, equal to 100 cm

mcf Thousand cubic feet

MI Hub Michigan Hub, a electricity pricing point on the MISO system

mmBtu Million Btu, a measure of energy content

MISO Midwest Independent Transmission System Operator, an ISO

MW Megawatt, a measure of generating capacity

MWh Megawatt hour, an energy unit for electricity sales

NEB National Energy Board of Canada

NG Natural gas

Nominal dollars Monetary value that has not been adjusted to remove the effects of general inflation

NYISO New York Independent System Operator

NYMEX New York Mercantile Exchange

NYPA New York Power Authority

Ont Int Ontario Interface, an electricity pricing point on the MISO system and an intertie between

the MISO and Ontario bulk electricity systems

Renewable

resources

Hydroelectric, wind, solar, geothermal, tidal, wave, biomass, and agricultural waste energy

resources; in this report, the term refers to sources of electricity only

SD Standard deviation, a statistical measure of variance

Short term Generally, two years

st Short ton, equal to 2000 pounds

tonne Metric ton, equal to 2200 pounds

UGL Upper Great Lakes

UP Upper Peninsula of Michigan (north of the Straits of Mackinac)

IJC Upper Great Lakes Electricity Forecasts ▪ 1

1. Executive Summary

This report is part of a larger study being conducted by the US-Canadian International Joint

Commission (IJC) of the Upper Great Lakes (UGL) region. The purpose of this report is the

development of future wholesale electricity prices relevant to the operation of the hydroelectric

facilities in this region.

With the recent economic downturn and the decline of natural gas prices, the current wholesale

electric market prices are down significantly from what they were a few years ago. Expectations are

for a gradual price recovery over time. For the Michigan Hub (MI Hub) location, wholesale electricity

prices (in constant dollars) are expected to rise from $32.8/MWh in 2011 to $39.2/MWh in 2020.

Historic prices have been significantly greater in some locations compared to others. For example,

prices in the Upper Peninsula (UP) of Michigan have historically averaged about 22% higher than the

MI Hub prices. Thus, hydroelectric generation serving the UP has a greater economic value than

generation serving the MI Hub.

Natural gas prices have been a major factor affecting electricity prices in the recent past and are likely

to continue be so in the future. Before 2009, natural gas prices were very volatile and much higher

than they are at present. With the development of unconventional natural gas resources, such as

shales for example, current expectations are that domestic supplies will be adequate for the next

several decades. Consequently, prices are expected to remain lower than prices prior to 2009,

although they will increase somewhat relative to currently depressed levels. Thus, the high prices and

volatility seen in the wholesale gas market in the past are unlikely to recur in the foreseeable future.

The largest uncertainty affecting future electricity prices is regulation of greenhouse gas emissions

(GHG) and the imposition of prices on emissions of carbon dioxide (CO2), the predominant GHG

emitted by the electric sector. A price on carbon could significantly increase the cost of coal and

natural gas generation and affect wholesale electricity prices. It is unknown at this time what path

such regulations might take. Thus, this report presents two electricity price forecasts: one with and one

without CO2 costs. In the absence of CO2 costs, electricity prices increase by about 40% over the

2011 to 2040 period (an average growth rate of 1.2%). If CO2 costs are included, real prices more

than double with an increase of 135% over the same period (an average growth rate of 3.2%).

In conclusion, electricity prices are expected to rise from their current low levels, but how fast and how

far they will rise is uncertain.


2. Historic and Current Electricity Generation

A. St. Marys

There are three hydro facilities on the St. Marys River near Sault Ste. Marie, as listed in the table

below and described more fully in Appendix A.

Exhibit 2-1: St. Marys Hydroelectric Facilities

Facility Operator Country Flow Capacity (cms)

Generating Capacity (MW)

Clerque Brookfield Renewable CA 1,140 54.6

Cloverland Cloverland Electric US 850 36

US Government US ACOE US 405 24

Total 2,395 115

The design head for these facilities averages close to six metres, but the actual operating head

depends on lake levels and water flows. For example, the Clergue plant can operate within the range

of 4.2~7.4 metres. The combined flow capacity of these facilities is 2,395 cubic meters per second

(cms). In addition, about 100 cms is needed for other purposes such as operating the locks, for

domestic and industrial purposes, and maintaining flow in the St. Marys Rapids.

The long term average (1918-2009) outflow from Lake Superior is 2120 cms, which varies by month

and by year.1 The hydro facilities generally operate at high capacity factors, but operations can vary

considerably depending on the outflow from Lake Superior and operating head at the plant. The graph

below shows the historical pattern of monthly Lake Superior outflows, which are slightly higher in the

summer and fall. There is a wide variation from year to year, as is indicated by lines at +/-1 standard

deviation as well as the minimum and maximum values. When the amount of water available for

hydropower purposes exceeds the plants total capacity, the un-useable portion is typically spilled at

the rapids and thus potential generation is lost.

1 Peter Yee, email message to author, November 8, 2010. and attached file “SUPFLOWM.TXT”.


Exhibit 2-2: Lake Superior Monthly Outflows i

Superior Monthly Outflows (1900-2010)

0

500

1,000

1,500

2,000

2,500

3,000

3,500

4,000

Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec

cm

s

Max

+1 SD

Average

-1 SD

Min

The amount of St. Marys River water available for hydropower purposes is determined on a monthly

basis at the beginning of each month. The amount is shared 50:50 between Canada and the United

States. For the U.S. share, the allocation is typically used by the US Government Plant owing to its

higher operating head, with the balance used by the Cloverland Plant. Some flexibility within the

month and day exists as to how the plant operators use their allocated water and the actual generation

patterns. Shifting generation within a 24 hour period to better match load and prices is known as

peaking operations. Shifting generation within a week (e.g. from the weekend to the week days) is

known as ponding. Those operations are limited by the need to maintain flow and water levels in the

lower St. Marys downstream of the plant.2 The key factor determining Lake Superior outflows is the

need to keep the levels of both Lake Superior and Lake Michigan-Huron about the same magnitude

relative to the monthly mean while taking into consideration their historical ranges. Water levels that

are either too high or too low can cause negative consequences along the lake shores.

The following exhibit with historic data for the Clerque facility indicates that while daily peaking is

common, weekly ponding is much less so. Maximum generation occurs in the hours between 0800

and 2100, with the minimum typically occurring around 0100. The difference between daily maximum

and minimum flow is about 310 cms, with the low flow representing about 68% of the daily peak. The

change is not abrupt and generally takes place over about a four hour period.

2 For reference, the upper reach of the St. Marys above the hydro facilities is 22 km while the lower reach to Lake Huron

is 77 km. See also the IJC draft report “Water Level Analysis of Lower St. Marys River”, September 15, 2010.


Exhibit 2-3: Weekly Patterns at Brookfield (Clerque) ii

Brookfield Average Weekly Flow Pattern (2007-2008)

0

100

200

300

400

500

600

700

800

900

1,000

1,100

Sun Mon Tues Wed Thur Fri Sat

Day of Week and Hour

cm

s

As indicated previously the St Marys hydro facilities have a total capacity of 115 MW and a maximum

flow rate of 2,395 cms. Since the average St. Marys flow is 2,120 cms this means that they operate at

an average capacity factor no more than 88% resulting in an average annual generation of 886 GWh

(including Canada). Michigan has a whole has a generating capacity of about 30,400 MW and annual

generation of 115,000 GWh.3 So the St. Marys facilities represent a fraction of a percent of that total.

Considering just the Upper Peninsula of Michigan the total generating capacity is 1,300 MW and the

average annual generation about 5,600 GWh, so the St. Marys facilities are proportionally much more

important in that context.

3 EIA State Electricity Profile, http://www.eia.doe.gov/cneaf/electricity/st_profiles/michigan.html


B. Niagara

There are a number of hydroelectric facilities in the Niagara area between Lakes Erie and Ontario,

which are listed in the table below and described more fully in Appendix A.

Exhibit 2-4: Niagara River and Welland Canal Hydroelectric Facilities

Location and Facility

Operator Country Flow Capacity (cms)

Generating Capacity (MW)

Niagara River

Beck 1 Ont. Power Gen. CA 549 417

Beck 2 Ont. Power Gen. CA 1,849 1,499

R.H.Moses NY Power Auth. US 2,832 2,755

Subtotal 5,230 4,671

Welland Canal

Weirs 1, 2 & 3 Rankin Renewable CA 23 6.4

ND1 (DeCew Falls) Ont. Power Gen. CA 38 23

NF23 (DeCew Falls) Ont. Power Gen. CA 193 144

Heywood St. Catharines Hydro CA 283 7.2

Subtotal 537 181

Total 5,767 4,853

The total flow capacity of all the plants in the Niagara River and in Welland Canal is more than twice

as much as the total flow capacity of the plants in the St. Marys, indicative of the larger watershed at

the outlet of Lake Erie. The operating heads for these facilities are generally between 80 to 90

meters, although some units on the Welland Canal and the PGS units operate at much lower heads.

The total generation capacity is almost 50 times greater than that of the St. Marys facilities, reflecting

the greater flows and the much greater heads of the Niagara.

The long term average outflow from Lake Erie is 5,900 cms, which varies by month and by year.4 The

hydro facilities generally operate at high capacity factors, but operations can vary considerably

depending on the actual outflow. The amount of water available for hydropower purposes is governed

by the Niagara River Treaty of 1950 which specifies minimum flows for Niagara Falls for various parts

of the year, season and day.

The graph below shows the historical pattern of monthly Lake Erie outflows, which are slightly higher

in the summer and fall. There is a moderate variation from year to year, as indicated by the lines at +/-

1 standard deviation (SD) as well as the minimum and maximum values. Water available for power

purposes exceeding plant capacity requires some water to be spilled over Niagara Falls and potential

generation to be lost.

4 Peter Yee, email message to author, November 8, 2010. and attached file “ERFLOWM.TXT”


Exhibit 2-5: Lake Erie Monthly Outflows iii

Erie Monthly Outflows (1900-2010)

0

1,000

2,000

3,000

4,000

5,000

6,000

7,000

8,000

9,000

Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec

cm

s

Max

+1 SD

Average

-1 SD

Min

While satisfying the minimum flow requirements for Niagara Falls, some flexibility exists in actual

generation patterns, though limited by the hydraulic factors in the Niagara River. Shifting generation

within a 24 hour period to better match electric load and prices is identified as peaking operations.

The analysis of the DeCew and Beck facilities’ generation patterns for 2005 through 2010 indicates

that peaking is common, with maximum generation occurring between the hours of 0900 and 2200

and peaking slightly in the evening. The daily minimum occurs at about 0300. The difference between

daily maximum and minimum generation is about 434 MW, with the low generation level representing

about 73% of the daily peak. The change is not abrupt and generally takes place over a four hour

period. No weekly ponding is apparent from these data.5

Total generation capacity in NY state is 38,700 MW and the Niagara hydro facilities with a capacity of

4,853 MW represent 12.5% of that total.


Exhibit 2-6: Generation Patterns at DeCew and Beck Hydroelectric Facilitiesiv

DeCew+Beck Average Weekly Generation Pattern (2005-2010)

0

200

400

600

800

1,000

1,200

1,400

1,600

1,800

Sun Mon Tues Wed Thur Fri Sat

Day of Week and Hour

MW

Our review of the hourly generation data for the New York Power Authority (NYPA) Niagara facility

found that its pattern of operations is very similar to that of DeCew and Beck.6 Generation throughout

the year is relatively flat, although less in the summer and fall and slightly more in the winter and

spring. The typical weekly generation pattern is also very similar, although the differences are greater

with the off-peak generation equal to about half of the peak generation. Peak generation is also

slightly lower on the weekend days. Generation varies slightly from year to year with the standard

deviation in the monthly generation from one year to the next being about 6.6%.

6 Rich Mueller (NYPA), email message to author, December 9, 2010.


3. Historic and Current Electricity Prices

Electricity costs and prices are a fairly complicated area, and the following discussion is intended to

give a better context for the subsequent price forecasts. Electricity production costs can be put into

two categories: fixed and variable. The fixed costs represent sunk costs that are incurred regardless

of how much electricity is generated. Typical examples of fixed costs are the initial construction costs

and fixed operating and maintenance expenses. Variable costs are typically fuel and other

consumables and additional variable operating and maintenance costs incurred because of the power

production. The distinction between some of the categories is fuzzy, and many regulatory

proceedings have focused on the fine points.

Under traditional utility regulation, the price to the customer is set to give the generator a fair rate of

return on the investment costs and to cover the variable and fixed operating costs. In such a system,

the marginal cost of generation (representing only the true variable costs) is known as the system

lambda. System lambda is used to order resources for dispatch but does not represent a customer

price.

Over the last decade or so, some regions have implemented a market based system for wholesale

power production managed by Independent System Operators (ISO). In such a system, the producers

submit bids for various products such as electric energy, capacity and ancillary services. Within a

market-based framework, the ISO decides which producers are called upon and what they receive in

payment. The local distribution companies pay the ISO for the services that they receive, and those

costs are then passed on to consumers through their electric bills. The wholesale energy market price

is determined by the bids submitted by producers and the level of demand. Although suppliers’ bids to

some degree represent their variable costs, the relationship between wholesale market prices and

total production costs is not clear cut. Because all suppliers receive the market clearing price, most

are paid more than their marginal energy costs. The revenue in excess of the suppliers’ marginal

energy costs goes to cover their fixed costs as well. Even when averaged over a year, there may be

some times when the market price is more than total production costs and some times when it is

less—although economists assert that over the long term it all averages out.

In the UGL region, the New York electric system is operated by an ISO market administrator (New

York Independent System Operator, or NYISO). Michigan is also within an ISO, the Midwest

Independent Transmission System Operator (MISO). Ontario operates in a more regulated hybrid

mode. In regards to the value of the UGL hydroelectric generation, the MISO and NYISO market

prices are the most relevant ones, since they reflect market relationships between supply and

demand. Thus, and consistent with the recommendations of the IJC advisory group, this analysis

uses the MISO Ontario Interface as the pricing point for the Canadian St. Marys generation. It is

important to remember, however, that the hydro facilities may not actually be paid the market price for

the energy they produce, but rather be paid under the terms of various contracts.

To give some context for the forecasts that appear in section 4 of this report, some historic and recent

price patterns are described below.


A. Monthly Prices

The following exhibit summarizes the monthly electricity prices in the areas of interest since 2005.

These are the MISO MI Hub7, the MISO Ontario Interface and the New York West Zone (NY West).

There has historically been substantial month to month volatility in all three of these areas—although

there is a general pattern of higher prices in the summer and winter months. In the last two years,

prices have been less volatile and have fallen to significantly lower levels as a result of general

economic conditions and lower natural gas prices. NY West prices, which were sometimes

significantly higher in the past, are now much closer to MI Hub prices. Although not shown here, the

prices reported for the Ontario Hub in recent years have been very close to those at the MISO Ontario

Interface.

Exhibit 3-1: Historic Wholesale Electricity Prices v

Historic Monthly Electricity Prices

0

10

20

30

40

50

60

70

80

90

100

3 4 5 6 7 8 910

11

12 1 2 3 4 5 6 7 8 9

10

11

12 1 2 3 4 5 6 7 8 9

10

11

12 1 2 3 4 5 6 7 8 9

10

11

12 1 2 3 4 5 6 7 8 9

10

11

12 1 2 3 4 5 6 7 8 9

2005 2006 2007 2008 2009 2010

$/M

Wh

NY West MI Hub Ont Int

7 This discussion focuses on the Michigan Hub since that has the most complete dataset. However, the MI Hub forecast

will be adjusted for St. Marys on the Upper Peninsula.


B. Period Prices

Electricity usage and prices are often separated into two periods, peak and off-peak, representing

specific hours during the week. To understand the relationship between peak and off-peak prices, this

discussion focuses on the MI Hub, which is fairly representative of the patterns throughout the UGL.8

The exhibit below shows that while off-peak prices vary from month to month, they do so in a fairly

limited range. Peak prices exhibit much greater variability, which is in large part related to the volatility

of natural gas prices. However, over the last two years, peak prices have been much less volatile and

have moved much closer to the off-peak prices.

Exhibit 3-2: Peak and Off-Peak Electricity Prices at the MI Hub ($/MWh) vi

Monthly Prices at: MICHIGAN.HUB

0

10

20

30

40

50

60

70

80

90

100

110

4 5 6 7 8 91

01

11

2 1 2 3 4 5 6 7 8 91

01

11

2 1 2 3 4 5 6 7 8 91

01

11

2 1 2 3 4 5 6 7 8 91

01

11

2 1 2 3 4 5 6 7 8 91

01

11

2 1 2 3 4 5 6 7 8 9

2005 2006 2007 2008 2009 2010

$/M

Wh

Peak

Of f-Peak

8 The MISO peak period is defined as the time between 0600 and 2200 hours Eastern Standard Time Monday through

Friday excluding specific holidays. Off-peak represents the remaining hours. This is often referred to as 5x16 (5 weekdays x 16 hours) per week. The NYISO uses the same definition, while Ontario’s is slightly different.


C. Electricity and Natural Gas Prices

Natural gas fired power plants are usually the ones that set wholesale electricity prices during peak

load periods in the Midwest and Northeast. The following exhibit illustrates this by plotting the monthly

peak period price at the MI Hub with the monthly natural gas price at Henry Hub (HH), the major

natural gas trading hub in the US. Although the match is not perfect, the relationship is quite clear.

Lower electricity prices in recent years reflect much lower natural gas fuel prices. Thus, a key factor in

near and intermediate term electricity prices are natural gas prices.

Exhibit 3-3: Natural Gas Prices at HH and Peak Period Electricity Prices at MI Hub ($/MWh and $/MMBtu) vii

Michigan Peak Period Electricity and Nat Gas Prices

0

20

40

60

80

100

120

4 5 6 7 8 910

11

12 1 2 3 4 5 6 7 8 9

10

11

12 1 2 3 4 5 6 7 8 9

10

11

12 1 2 3 4 5 6 7 8 9

10

11

12 1 2 3 4 5 6 7 8 9

10

11

12 1 2 3 4 5 6 7 8 9

2005 2006 2007 2008 2009 2010

Peak E

lec P

rice (

$/M

Wh

)

0

2

4

6

8

10

12

14

16

HH

NG

Pri

ce (

$/m

mB

tu)

Peak Period Price HH NG Price


4. Wholesale Electricity Price Forecast

The primary factors affecting future electricity prices are generation mix, fuel prices, and costs of

greenhouse gas (GHG) emissions, with CO2 being the predominant GHG emitted by the electric

sector. The generation mix changes slowly (i.e., it takes two to ten years to add new capacity,

depending largely on the type of generation, but it takes much longer to make a significant change in

the overall mix). However, there will likely be more variable, renewable generation resources

(predominantly wind and solar resources) in the future mix on both sides of the border. Fuel prices are

less certain, although the North American natural gas market has become more stable in the last few

years and will likely remain so for a while. At some future time, costs of CO2 emissions will be

reflected in electricity prices, however when that will happen and the actual price impacts are

uncertain.

A. Electricity Futures

The best indicator of short term (two year) electricity prices is the futures market. The electricity futures

market currently goes out three to four years for the NY West zone, although trading is thin in the later

periods. Exhibit 4-1, below, shows the future market prices for electricity in the NY West zone.9 In the

short term, prices are higher in the summer and winter. Peak period prices are about $10/MWh above

the off-peak prices. The average peak period price is about $40/MWh, which is only slightly higher

than the actual 2010 prices shown previously in Exhibit 3-1.

Exhibit 4-1: Electricity Futures for NY West viii

NY West Futures

0

10

20

30

40

50

60

1 2 3 4 5 6 7 8 910

11

12 1 2 3 4 5 6 7 8 9

10

11

12 1 2 3 4 5 6 7 8 9

10

11

12

2011 2012 2013

$/M

Wh

Peak

Off-Peak

9 Based on NYMEX settlement data from CME Group, “CME ClearPort Clearing: Final Post-Clearing Prices as of

11/15/10.” Some of the regularities in the month to month prices reflect the fact that some contracts are for two or more months.


For Michigan, making use of the futures is more complicated. Future prices for the MI Hub only go out

to the middle of 2011. However, futures for the nearby Cinergy Hub go out through 2014, and the

patterns for the two hubs are very similar. For this analysis, the MI Hub prices are calibrated to the

Cinergy futures to develop a forecast for the MI Hub price. Further adjustments are then made based

on historic data to arrive at prices for the Upper Peninsula and for the Ontario Interface.

Exhibit 4-2: Electricity Futures for MI and Cinergy Hubs ix

Cinergy and Michigan Hub Futures

0

5

10

15

20

25

30

35

40

45

50

55

1 2 3 4 5 6 7 8 91

01

11

2 1 2 3 4 5 6 7 8 91

01

11

2 1 2 3 4 5 6 7 8 91

01

11

2 1 2 3 4 5 6 7 8 91

01

11

2 1 2 3 4 5 6 7 8 91

01

11

2

2010 2011 2012 2013 2014

$/M

Wh

Cinergy Peak

Cinergy Of f-Peak

MI Peak

MI Off -Peak


B. NY West Short-Term Forecast

For this analysis, the NYMEX NY West futures are directly used as the short-term forecast for the

Niagara and Wells Canal facilities. The results of the analysis are given in the table below. The

monthly pattern is a typical one, with higher summer and winter prices and lower spring and fall ones.

These prices are in nominal dollars, reflecting the actual futures prices. The annual values are also

given in constant dollars in the long term forecast tables in section D of this report.

Exhibit 4-3: NY West (Niagara) Short Term Forecast x

All-Hours Ratio

Year Month NY-West Peak/All Hours

2011 1 38.9 1.10

2 38.9 1.10

3 34.8 1.11

4 34.8 1.11

5 33.2 1.11

6 34.1 1.12

7 39.4 1.13

8 39.4 1.13

9 34.8 1.10

10 35.9 1.09

11 35.9 1.09

12 35.9 1.09

2012 1 41.5 1.11

2 41.5 1.11

3 37.0 1.12

4 37.0 1.12

5 34.3 1.13

6 35.4 1.15

7 41.8 1.12

8 41.8 1.12

9 35.7 1.14

10 37.3 1.12

11 37.3 1.12

12 37.3 1.12


C. Michigan Short-Term Forecast

For the short term forecast for the St. Marys facilities, MISO futures are adjusted based on historic

price relationships between different locational wholesale electricity markets. The following exhibit

shows the results of those calculations. Historically, prices in Michigan’s Upper Peninsula (UPM) have

been considerably higher than for the MI Hub, while the Ontario Interface10 prices have been slightly

less. Prices in Exhibit 4-4 are in nominal dollars, reflecting the actual futures prices.

Exhibit 4-4: Michigan Short Term Forecast xi

All-Hours Prices ($/MWh) Ratio

Year Month MI Hub Ont-Int UPM Peak/All Hours

2011 1 34.7 32.3 42.4 1.13

2 34.7 32.3 42.4 1.13

3 32.4 30.2 39.6 1.18

4 31.9 29.7 39.0 1.16

5 30.4 28.3 37.2 1.21

6 31.7 29.6 38.8 1.22

7 37.8 35.2 46.2 1.25

8 37.8 35.2 46.2 1.25

9 31.7 29.6 38.8 1.23

10 31.8 29.7 38.9 1.20

11 31.8 29.7 38.9 1.20

12 31.8 29.7 38.9 1.20

2012 1 37.0 34.5 45.2 1.22

2 37.0 34.5 45.2 1.22

3 35.7 33.3 43.7 1.18

4 35.7 33.3 43.7 1.18

5 35.1 32.7 42.9 1.17

6 36.2 33.8 44.3 1.20

7 40.3 37.6 49.3 1.29

8 40.3 37.6 49.3 1.29

9 36.1 33.6 44.1 1.19

10 35.9 33.4 43.9 1.19

11 35.9 33.4 43.9 1.19

12 35.9 33.4 43.9 1.19

10

The Ontario price is based on the Ontario Interface of the Midwest ISO, as that is a more liquid market with active futures contracts. Historic analysis has also shown that prices there have been close to those of the Ontario hub.


D. Long Term Forecasts

There are many unknowns affecting long-term electricity prices. Some of those are:

1. Load growth

2. Fuel prices

3. Generation mix and renewable energy requirements

4. GHG and other environmental regulations

Few long-range forecasts of energy prices exist. The results of those analyses strongly depend on a

few key assumptions, which are sometimes not well specified. In 2009, Synapse conducted a forecast

of New England electricity prices through 2024.11 The key factor driving electricity market prices was

the forecast of natural gas prices, which is discussed in some detail in that report. The most

comprehensive and best documented energy forecast for the US is produced each year by the US

Energy Information Administration (EIA) and is called the Annual Energy Outlook (AEO). The AEO

considers all aspects of the US energy system and presents both a reference case as well as a

number of alternative scenarios. AEO 2009 was the basis for the New England forecast and we use

the more recent AEO 2010 for the analysis underlying this report.

For this forecast, the year-by-year variations in the AEO 2010 reference case electric generation cost

forecast for the ECAR region are smoothed out. The AEO forecast predicts that real electricity costs

in the ECAR region will increase at about 1% per year in real terms after 2012. That growth rate

underlies the base forecast shown below. Prices for the first two years (2011 and 2012) are the same

as presented previously in the short term forecasts based on electricity futures but are now presented

in constant 2010 dollars. Exhibit 4-5 shows projected average annual wholesale electricity prices and

price growth rate, excluding the effects of CO2 emissions regulation, over the 30 year period. These

prices are reported in constant dollars to better represent the real changes and exclude the effects of

an unknown future rate of inflation. In real terms, electricity prices increase by about 40% over this

period.

The long-term forecasts shown below represent mid-range average prices and do not reflect the

typical variations that occur from one year to the next.

11

Synapse Energy Economics 2009. Avoided Energy Supply Costs in New England: 2009 Report. Prepared for the Avoided Energy Supply Component (AESC) Study Group. August 2009. http://www.synapse-energy.com.


Exhibit 4-5: Long Term Forecast of Electricity Prices and Compound Annual Growth Rates (CAGR) Without CO2 Costs, 2011 - 2040

xii

$/MWh (2010 $)

Year MI Hub Ont-Int UPM NY West

2011 32.8 30.6 40.1 35.9

2012 36.2 33.8 44.3 37.6

2013 36.6 34.1 44.8 38.0

2014 37.0 34.5 45.2 38.4

2015 37.3 34.8 45.7 38.8

2016 37.7 35.2 46.1 39.2

2017 38.1 35.5 46.6 39.5

2018 38.5 35.9 47.0 39.9

2019 38.9 36.2 47.5 40.3

2020 39.2 36.6 48.0 40.7

2021 39.6 37.0 48.5 41.2

2022 40.0 37.3 48.9 41.6

2023 40.4 37.7 49.4 42.0

2024 40.8 38.1 49.9 42.4

2025 41.2 38.5 50.4 42.8

2026 41.7 38.8 50.9 43.2

2027 42.1 39.2 51.4 43.7

2028 42.5 39.6 52.0 44.1

2029 42.9 40.0 52.5 44.6

2030 43.4 40.4 53.0 45.0

2031 43.8 40.8 53.5 45.5

2032 44.2 41.2 54.1 45.9

2033 44.7 41.6 54.6 46.4

2034 45.1 42.1 55.2 46.8

2035 45.6 42.5 55.7 47.3

2036 46.0 42.9 56.3 47.8

2037 46.5 43.3 56.8 48.3

2038 46.9 43.8 57.4 48.7

2039 47.4 44.2 58.0 49.2

2040 47.9 44.6 58.5 49.7

CAGR 1.3% 1.3% 1.3% 1.1%

The AEO forecast does not include any effects of CO2 emissions regulation, which the authors believe

to be inevitable despite of the current state of the US Congress. In 2008 Synapse produced a report12

looking at likely future prices for emissions of CO2. Synapse is currently engaged in an update of that

2008 report, and the preliminary results are shown in the following table. For the CO2 mid case the

price starts at $15 per short ton (st) of CO2 (2010$) in 2018 and increases to $50/st by 2030. By 2030

the CO2 costs add about $22/MWh to the wholesale price of electricity. The overall effect is that the

real electricity prices increase by about 135% over the thirty year forecast period.13

12

Synapse Energy Economics 2008. Synapse 2008 CO2 Price Forecasts. July 2008. http://www.synapse-energy.com. 13

In the AESC 2009 report (referenced previously), the wholesale electricity price in 2010 is $58.9/MWh and increases to $87.1/MWh in 2024, which is a 48% increase over a 14 year period.


Exhibit 4-6: Long Term Forecast with CO2 Costs xiii

$/MWh (2010 $)

Year MI Hub Ont-Int UPM NY West

2011 32.8 30.6 40.1 35.9

2012 36.2 33.8 44.3 37.6

2013 36.6 34.1 44.8 38.0

2014 37.0 34.5 45.2 38.4

2015 37.3 34.8 45.7 38.8

2016 37.7 35.2 46.1 39.2

2017 38.1 35.5 46.6 39.5

2018 45.1 42.5 53.7 46.6

2019 46.8 44.2 55.4 48.3

2020 48.5 45.8 57.2 50.0

2021 50.1 47.5 59.0 51.7

2022 51.8 49.1 60.7 53.4

2023 53.5 50.8 62.5 55.1

2024 55.2 52.5 64.3 56.8

2025 56.9 54.1 66.1 58.5

2026 58.6 55.8 67.9 60.2

2027 60.3 57.5 69.7 61.9

2028 62.0 59.2 71.5 63.7

2029 63.8 60.9 73.3 65.4

2030 65.5 62.5 75.1 67.1

2031 67.2 64.2 76.9 68.9

2032 68.9 65.9 78.8 70.6

2033 70.7 67.6 80.6 72.4

2034 72.4 69.3 82.4 74.1

2035 74.1 71.1 84.3 75.9

2036 75.9 72.8 86.1 77.6

2037 77.6 74.5 88.0 79.4

2038 79.4 76.2 89.8 81.2

2039 81.2 77.9 91.7 83.0

2040 82.9 79.7 93.6 84.7

CAGR 3.3% 3.4% 3.0% 3.0%

As shown in the following exhibit, CO2 costs could significantly increase future wholesale electricity

prices. The CO2 price impacts shown assume that the average marginal generating unit setting the

wholesale price will be burning natural gas with an emission rate of 0.44 short tons of CO2 per MWh

generated. For coal units on the margin, the emission rate and the price impact would be twice as

much.


Exhibit 4-7: Long Term Forecast with and without CO2 Costs xiv

Michigan Hub Electricity Prices

0

10

20

30

40

50

60

70

80

90

2011 2016 2021 2026 2031 2036

2010$/M

Wh

With CO2 Costs

No CO2 Costs

There may be some factors offsetting the upward pressure on electricity prices from CO2 costs. For

example, carbon capture and storage may become technically feasible and put a price cap on the CO2

cost impacts. Another possibility is that non-carbon variable generating resources along with

electricity storage could set the marginal wholesale price during many hours. For example, generation

from wind resources might approach or exceed the load during some hours, resulting in zero or

negative energy prices. Variable generation cannot, however, entirely displace the need for

dispatchable generation whose costs would not be reflected in the energy prices but in ancillary

services such as spinning reserve.

Hydroelectric resources that can be ramped up or down rapidly to compensate for variations in wind

generation could be very valuable. However, the current UGL hydro facilities are not being operated

that way, and such operation could have a number of negative environmental effects. Smokorowski et

al. released a study of the environmental impacts of lifting ramping rate restrictions on the Steephill

Falls hydroelectric facility on the Magpie River in Ontario (north of the St Marys). The study found that

unlimited ramping was associated with channel widening, incision, alteration of natural bedload

movements, a reduction in invertebrate diversity, and a change in fish diets and food web complexity.

Based on a preliminary review of economic modeling, the same study found that hydroelectric

generation profits were potentially insensitive to ramping over a limited range of ramping. To the extent

that the Steephill Falls facility could sell generation into the Ontario and MISO markets, the results of

the Smokorowski study are relevant. Nevertheless, operational shifts might be worth investigating for

the facilities considered in this report, which have different sources, aquatic ecosystems, and daily and

seasonal flow patterns than the Magpie River.


Monthly prices can be derived from the annual prices given above in Table 4-5 or 4-6 by applying the

monthly variations shown in the table below. This table shows the monthly variations from the annual

average based on historic price data since 2005. It is important to note that variations from year to

year are very large and occasionally several times larger than the average variations given here.

Exhibit 4-8: Monthly Price Variation from the Annual Average xv

Month MI Hub Ont Int UPM NY West

1 3% 12% 8% 14%

2 10% 18% 14% 9%

3 0% 5% 3% -6%

4 -5% -3% -11% -8%

5 -12% -11% -10% -15%

6 8% 4% 0% 0%

7 9% 6% 2% 10%

8 14% 6% 8% 8%

9 -12% -21% -11% -3%

10 -3% -6% 1% -3%

11 -12% -10% -11% -7%

12 0% 0% 12% 4%

Absent major changes in the generation resource mix, future monthly price patterns and peak period

price ratios are likely to be similar to those of today (see Exhibits 4-3 and 4-4). However, major

additions of renewable generation such as wind could result in changes in these price patterns,

especially during periods when generation from those resources is high relative to load. Analysis of

the possible effects of a major shift towards renewable generation might be depend on many factors,

and extensive system dispatch simulations would be needed to better quantify them.


5. Peak Price Ratios

A. Historic Patterns

Peak period price ratios are determined more by changes in peak period prices rather than changes in

off-peak prices. The table below shows the annual period prices since 2005 at the MI Hub, which is

representative of other locations in the UGL region. For 2005 through 2008, the peak prices were

substantially more than the off-peak prices, and the price ratio was about 1.80. In 2009, peak period

prices declined sharply largely because of the collapse of natural gas prices and reduced demand for

electricity. Although off-peak prices also declined some, the price ratio fell to about 1.45 in 2009 and

2010, reflecting the dramatic drop in peak period prices. Over this nearly six year period, the peak

period price ratios have changed considerably, ranging from an annual low of 1.40 to a high of 1.88.

Because it is based on both peak and off-peak prices, the peak to all-hours ratio varies less than the

peak to off-peak price ratio. From 2005 to 2010, the peak to all-hours price ratio varied from 1.17 to

1.32. However, even as the peak to all-hours price ratio shows little variation, the annual average all-

hours energy price varies substantially from $30.7 to $54.1 per MWh.

Monthly price ratios exhibit even greater variation. The highest peak/off-peak price ratio during this

period was 2.76 in July of 2008. The lowest ratio was 1.29 in March of 2009.

The authors expect that the considerable variation in price ratios seen in recent historic data could

likely continue in the future.

Exhibit 5-1: Electricity Price Ratios xvi

Michigan Hub Electricity Prices ($/MWh)

Year Off-Peak Peak All-Hours Peak/ Off-Peak Ratio

Peak/ All-Hours Ratio

2005 38.2 71.7 54.1 1.88 1.32

2006 32.7 55.2 43.4 1.68 1.27

2007 35.3 62.9 48.4 1.78 1.30

2008 37.6 68.0 52.1 1.81 1.30

2009 25.1 36.9 30.7 1.47 1.20

2010 (9 mo) 31.3 43.7 37.2 1.40 1.17

Average 33.4 56.4 44.3 1.67 1.26


B. Possible Future Patterns

In the near term, the price ratios would be primarily affected by the price of natural gas, which is a

primary determinant of peak period electricity prices. Current expectations are that gas prices will

increase at a modest rate but not reach previous highs for a decade or more. Thus, the price ratios

are likely to modestly increase from the current lows. Longer term ratios are less certain since they

depend on the generation mix, the comparable fuel prices and the effects of GHG regulation.

Baring major system changes, the cost of coal generation will determine the off-peak electricity prices

for the UGL region. While the price of coal is unlikely to change dramatically, emission regulations will

likely increase coal generation costs. The biggest uncertainty lies with GHG regulation, where a

$10/st cost for CO2 would increase the cost of coal generation by approximately $10/MWh. CO2

prices of $40/st or more could raise coal costs up to those of natural gas.

Peak period prices, especially for high load hours, will be set by the cost of natural gas combined cycle

generation. Current natural gas prices and future forecasts are at relatively low levels, making efficient

natural gas generation competitive with higher cost coal plants. However, natural gas prices have

shown considerable volatility and been higher in the past, and that could be the case again especially

when going out several decades. GHG regulation has a smaller impact on combined cycle natural gas

generation than on coal. A CO2 cost of $10/st would increase the cost of NG generation by

approximately half as much, or $5/MWh.

A complicating factor is the effect of adding large amounts renewable generation capacity, which is

likely to be predominately wind in the UGL region. Wind is a variable but increasingly predictable

generation source. It has to be used when available or lost, and thus it is a “price taker”, that is it must

accept the market clearing price if it is not sold through a bilateral contract or used by the generation

owner. Much wind generation is likely to occur during the off-peak hours and displace some coal

generation, perhaps even moving prices towards zero in some hours. New, faster-ramping natural

gas capacity may have to be dispatched in many hours instead of coal units, which take a while to

ramp up and down. The precise impact of renewable energy on energy prices is complicated and

depends on many factors, but the net effect will be a downward effect on electricity wholesale prices.

Another factor affecting price ratios could be changes in demand resulting from energy efficiency

programs and smart grid initiatives. The primary effect of such programs would be to reduce peak

period prices, but they might reduce off-peak prices as well. The likely overall effect would be to

reduce the peak to off-peak price ratios. A system dispatch analysis would be required to quantify

those effects.

Further discussion of marginal generation and costs can be found in the section C of the Appendix.


6. Price Uncertainty

A. Overview

The primary factors affecting short-term electricity prices are natural gas prices and loads. For the

longer term, the major factors are: natural gas prices, loads, generation mix including renewables,

and CO2 costs.

B. Fuel Prices

One can view forecast uncertainty either in a prospective or a retrospective manner. The prospective

approach looks at the primary factors affecting future values and makes some judgment about their

uncertainty, perhaps based on historic patterns or an analysis of economic fundamentals.

The following figure from AEO 2010 shows the range of natural gas prices associated with several

cases that assume different rates of technology development.14

All of the cases show a near term

increase to about $6 per thousand cubic feet (mcf) and differing rates of increase thereafter. However,

by 2035 the differences are fairy modest, ranging from a little more than $7 to a little less than $9/mcf.

Exhibit 6-1: Annual Average Wellhead Natural Gas Prices for Lower 48 States in Three Technology Cases, 1990-2035 (2008 $/mcf)

Source: AEO 2010, Figure 71, p. 71

For another perspective, the American Gas Association in 2009 in their Vision 2020 report15 made the

following predictions:

Natural gas is unlikely to remain at $4 per million Btu (mmBtu) or less, although prices may

continue to decline before they rebound,

For the forecast period, market equilibrium in the $6 to $8 range is possible,

14

US Energy Information Administration (EIA) 2010. Figure 71 on page 71. 15

American Gas Association. Vision 2020 and the Outlook for Natural Gas Markets. April 2009. http://www.aga.org/SiteCollectionDocuments/ResearchStats/090402VISION2020.PDF


Electricity generation demand for gas may increase gas price volatility, due both to seasonal

electricity demand spikes as well as the impacts of backing-up wind and other intermittent

electricity sources,

Climate change legislation will exacerbate the upward movement in energy prices,

Electricity prices may move upwards more than other energy forms, as both generating fuels

and capital costs for new plants will be affected.

Yet another forecast of future natural gas prices appears in the National Energy Board (NEB) of

Canada’s 2009 energy market report.16

Here the 2020 prices range from $5 to $11 per mmBtu.

Exhibit 6-2: Henry Hub Natural Gas Prices, Reference CaseScenario and Price Cases (2008 $US/MMBtu)

Source: NEB, July 2009

A more recent forecast of natural gas prices was produced in November 2010 by Black & Veatch for

the state of Alaska.17 The following graph shows three natural gas price scenarios from that report.

As with AEO 2010, there is an expectation of some near term price increases followed by more

gradual rises thereafter. For comparison with AEO 2010, the 2035 prices range from about $6.25 to

$9.50/MMBtu.

16

(Canada) National Energy Board. 2009 Reference Case Scenario: Canadian Energy Demand and Supply to 2020. July 2009. http://www.neb-one.gc.ca/clf-nsi/rnrgynfmtn/nrgyrprt/nrgyftr/nrgyftr-eng.html. 17

Black & Veatch. Shale Resources: Understanding Implications for North American Natural Gas Prices. Prepared for the state of Alaska, November 2010.


Exhibit 6-3: Henry Hub Natural Gas Price in Three Scenarios (2010 $US/mmBtu)

Source: Black & Veatch, November 2010, Figure 1-2.

The outlook for future natural gas prices has also been discussed in some detail in recent testimony

filed by Rick Hornby of Synapse.18

The key findings are reproduced below.

The long-term outlook for gas prices has changed dramatically in the past few years primarily due

to significant developments in the production of shale gas.

Shale gas is now generally viewed as the long-term marginal source of gas in North America.

This means that the cost of producing shale gas is expected to set the market price. Due to the

apparent availability of ample quantities of relatively low cost shale gas, and declines in gas use

due to the recession, natural gas prices in 2009 and 2010 to date were substantially lower than

prices in the prior years. Moreover, as indicated by the annual average of the NYMEX futures

prices for Henry Hub plotted on page 1 of Exhibit JRH-4, gas prices are expected to remain

below $5.50 through 2013 and possibly longer.

Analysts attribute the likely continuation of relatively low prices in the short-term to factors such

as drilling to hold leases by production, production from liquids-rich plays such as the

southwestern Marcellus Shale, the need to further delineate the size of plays, and existing high-

priced hedges. Thus these current spot prices do not appear to represent the long-term, full

replacement cost of shale gas. However, there is considerable uncertainty within the gas industry

as to what that long-term replacement cost is and when gas prices will start to reflect it.

The estimates I have reviewed, in addition to the various AEO forecasts, place the long run

marginal cost of shale gas between $6/MMBtu and $8/MMBtu. The reference case projections in

the Energy Information Administration’s Annual Energy Outlook (AEO) 2010 fall within that range

as indicated in Exhibit JRH-4. That Exhibit also presents the EIA long-term projections of Henry

Hub prices from AEO 2008 and AEO 2009.

18

Hornby, J, Richard. Direct testimony before the Arkansas Public Service Commission. November 2010: 23-24.


Thus while there are uncertainties about the future prices of natural gas especially in the longer term,

most current expectations are that will remain at modest levels for the near to intermediate future.

C. Renewables

Since renewable generation resources other than biomass and hydroelectric facilities are not

dispatchable, they generally do not set the market price. They may however affect the energy market

price indirectly by displacing other generation. Cost reductions in the energy market may be offset by

cost increases in the ancillary services markets, such as for spinning reserves.

An example of the effects of increased renewable generation can be seen in the current Ontario Long

Term Energy Plan.19 That plan incorporates a significant decrease in coal generation by 2020 along

with a quintupling of wind generation and a significant increase in conservation. Customer electricity

prices are expected to increase in real terms through about 2020 and stay level thereafter. Residential

prices are expected to increase by about two thirds (from figure 15), reflecting a large increase in fixed

costs associated with new renewable generation capacity. The report has no discussion of wholesale

electricity prices.

A value of existing hydro generation might be deduced by what is being offered for new clean

generation. The Ontario Power Authority (OPA) is offering a Feed-in Tariff (FIT) for new renewable

generation. For on-shore wind energy projects, they are offering a 20 year contract at a price of

13.5 ¢/kWh ($135/MWh),20

which is somewhat higher than wholesale market price forecasts if carbon

costs are included and considerably higher than the price forecasts if carbon costs are not included.

D. Carbon Emission Costs

There is great uncertainty about future carbon emission costs. Something will have to be done to

control global climate change, and reducing CO2 emissions will have to be part of that. While US

federal legislative action is unlikely in the next several years, the US Environmental Protection Agency

may take action in the meantime and various states are also moving forward.

In 2008, Synapse looked at the various legislative proposals for mitigating CO2 emissions and public

analyses of the CO2 reduction impacts and CO2 prices that would likely result from implementation of

these bills. 21 The exhibit below, excerpted from that report, shows the wide range of CO2 price

forecasts from those various studies through 2030. At that time, Synapse developed a set of three

forecasts representing a reasonable range of future possibilities. The mid case price for 2030 was

$53/st CO2. The high case price was 28% greater than the mid case price, and the low case price

was 57% lower. Although actual CO2 prices could possibly be outside of that range, it roughly

quantifies the uncertainty in future CO2 emission costs.

19

Ontario Ministry of Energy, Ontario’s Long-Term Energy Plan, 2010. http://www.mei.gov.on.ca/en/energy/ 20

Ontario Power Authority, 2010. ”Renewable Energy Feed In Tariff Program: Quick Facts Table,” http://fit.powerauthority.on.ca/Page.asp?PageID=122&ContentID=10186&SiteNodeID=1100&BL_ExpandID=259 (accessed January 14, 2011) 21

Synapse 2008.


Exhibit 6-3: CO2 Price Forecasts vs. Results of Modeling Analyses of Major Congressional Bills – Annual CO2 Prices ($ 2007/st)

Source: Synapse 2008.

To provide a Canadian perspective, the going assumption is that fairly stiff carbon prices are needed

to reach Canada’s announced target. Here are a couple of trajectories:

$15/tonne CO2e in 2010 to $115/tonne CO2e by 2020 (Bataille et al. 2009)

$100 per tonne of CO2e by 2020 and upward of $300 per tonne of CO2e by 2050 (NRTEE

2009)

E. Summary

The major uncertainties affecting future electricity prices in relative order of importance are: (1) Natural

gas prices in the near term and (2) CO2 prices in the longer term. It is also important to keep in mind

that wholesale energy market prices may not represent the full value of generation from hydroelectric

resources.


7. Emissions Impacts

A. Mechanisms for Emission Changes

As indicated in the previous sections, the current UGL hydroelectric facilities operate in a hybrid

baseload-peaking mode. As shown in Exhibits 2-3 and 2-6, the minimum weekly output is about 70%

of the peak levels. The total amount of hydro energy available is limited by lake outflows, which are

subject to natural variation and offer limited opportunity for human control. Thus, at present the

hydroelectric generation is displacing a mix of peak and off-peak resources. In the UGL region, the

off-peak resources are primarily coal, and the peak resources are a mix of coal and natural gas.

The following exhibit shows the historic average emission rates for the US Midwest, which are fairly

indicative of the UGL region. Note the substantial SO2 rate, which is associated with coal-fired

generation. These rates will decline in the future as emission controls are added to more plants and

older plants retire. What is unlikely to be affected are the CO2 rates, as there are no currently

available emission controls for that gas.

Exhibit 7-1: Midwest Electric Generation Emission Rates in 2005 22

xvii

Pollutant Midwest Reliability Organization

NOx Annual Rate 3.58 lb/MWh

NOx Ozone Season rate 3.41 lb/MWh

SO2 rate 5.87 lb/MWh

CO2 rate 1,811

lb/MWh

CH4 rate 27.94 lb/GWh

N2O rate 30.66 lb/GWh

Mercury (Hg) rate 0.039 lb/GWh

The potential for emission impact effects from UGL hydro facilities appear limited because of current

operational constraints. If the facilities had greater flexibility, then they could provide more peaking

energy and thus reduce emissions during peak load hours. However, displacing peak natural gas

generation but increasing off-peak coal generation might decrease some emissions but increase

others. Evaluation of the effects of such operation would require a system dispatch analysis. Also,

such changes to hydro operation would have other environmental effects and would require increasing

the peak generating capacity at those stations.

22

Extracted from US Environmental Protection Agency. eGRID (2005 data). http://www.epa.gov/cleanenergy/energy-resources/egrid/index.html.


8. Appendices


A. Bibliography

American Gas Association. Vision 2020 and the Outlook for Natural Gas Markets. April 2009.

http://www.aga.org/SiteCollectionDocuments/ResearchStats/090402VISION2020.PDF

Battaille, Chris, Benjamin Dachis, and Nic Rivers. “Pricing Greenhouse Gas Emissions: The Impact on

Canada’s Competitiveness.” C.D. Howe Institute COMMENTARY 280, (Feb 2009): 5.

Black & Veatch. Shale Resources: Understanding Implications for North American Natural Gas Prices.

Prepared for the state of Alaska, November 2010.

http://www.dog.dnr.state.ak.us/oil/agia/newsroom/Presentations/BV%20AK%20LT%20Prices%20Rep

ort%2011232010.pdf

(Canada) National Energy Board. 2009 Reference Case Scenario: Canadian Energy Demand and

Supply to 2020. July 2009. http://www.neb-one.gc.ca/clf-nsi/rnrgynfmtn/nrgyrprt/nrgyftr/nrgyftr-

eng.html.

CME Group, “CME ClearPort Clearing: Final Post-Clearing Prices as of 11/15/10.”

http://www.cmegroup.com/market-data/settlements/

Hydropower Technical Work Group International Upper Great Lakes Study. Coping Zones of

Hydropower Operations in the Great Lakes – St. Lawrence River System. Draft: January 6, 2011.

International Joint Commission (IJC). Water Level Analysis of Lower St. Marys River. (draft report).

September 15, 2010.

Hornby, J, Richard. Direct testimony before the Arkansas Public Service Commission. November

2010.

Independent Electricity System Operator, Ontario Reliability Outlook December 2009,

http://www.ieso.ca/imoweb/ircp/reliability_outlook.asp.

Midwest ISO, Midwest ISO 2010 Summer Assessment Report, October 20, 2010.

http://www.midwestiso.org/publish/Document/6a7e86_12bc0f1b440_-7f500a48324a?rev=1.

Midwest ISO, Midwest ISO 2010 Winter Assessment Report, April 07, 2010.

http://www.midwestiso.org/publish/Document/15cf2f_128d94d853e_-7f500a48324a?rev=1

National Round Table on the Environment and the Economy. Achieving 2050: A Carbon Pricing Policy

for Canada. 2009. http://www.nrtee-trnee.com/eng/publications/carbon-pricing/carbon-pricing-eng.php.

Ontario Ministry of Energy, Ontario’s Long-Term Energy Plan, 2010.

http://www.mei.gov.on.ca/en/energy/.

Ontario Power Authority, 2010. ”Renewable Energy Feed In Tariff Program: Quick Facts Table,”

http://fit.powerauthority.on.ca/Page.asp?PageID=122&ContentID=10186&SiteNodeID=1100&BL_Expa

ndID=259 (accessed January 14, 2011).

Patton, David et al, 2009 State of the Market Report: New York ISO,

http://www.nyiso.com/public/webdocs/documents/market_advisor_reports/2009/NYISO_2009_SOM_F

inal.pdf

Smokorowski, Karen E., Robert A. Metcalfe, Nicholas E. Jones, Jérôme Marty, Shilei Niu, and

Richard S. Pyrce. “Flow Management” Studying Ramping Rate Restrictions.” HydroWorld.com 28 (5).


http://www.hydroworld.com/index/display/article-display/366369/articles/hydro-review/volume-

28/issue-5/Featured_Articles/flow-management-studying-ramping-rate-restrictions.html.

Synapse Energy Economics 2008. Synapse 2008 CO2 Price Forecasts. July 2008.

http://www.synapse-energy.com.

Synapse Energy Economics 2009. Avoided Energy Supply Costs in New England: 2009 Report.

Prepared for the Avoided Energy Supply Component (AESC) Study Group. August 2009.

http://www.synapse-energy.com.

US Energy Information Administration (EIA) 2008. “Annual Energy Outlook Retrospective Review:

Evaluation of Projections in Past Editions (1982-2008),” DOE/EIA-06403(2008). Washington: Energy

Information Administration.

http://www.eia.doe.gov/oiaf/analysispaper/retrospective/pdf/0640%282008%29.pdf

US EIA 2009a. (Conti, John, Paul Holtberg, Joseph Beamon, A. Michael Schaal, Glen Sweetnam,

Andy Kydes, Kay Smith, et al.) “Annual Energy Outlook 2009 with Projections to 2030” DOE/EIA-

0383(2009). Washington: Energy Information Administration.

US EIA 2009b.” Annual Energy Review 2009” DOE/EIA-0384(2009). Washington: Energy Information

Administration.

US EIA 2010. (Conti, John, Paul Holtberg, Joseph Beamon, A. Michael Schaal, Glen Sweetnam, Andy

Kydes, et al.) “Annual Energy Outlook 2010 with Projections to 2035.” DOE/EIA-0383(2010).

Washington: Energy Information Administration.

US Environmental Protection Agency. eGRID (2005 data). http://www.epa.gov/cleanenergy/energy-

resources/egrid/index.html.


B. Hydro Generating Stations Summary Characteristics

Generating Stations - General Features

Operator/Owner Intake Point Return Point Flow Capacity,

cms

Generating Capacity,

MW

Operating/Rated Head

St. Marys River

Clergue Brookfield Renewable Above St. Marys Rapid Below Rapids 1140 (1) 54.6 (2) 5.7 m (2)

Cloverland Cloverland Electric Above St. Marys Rapid Below Rapids 850 (4) 36 5.5 ~ 6.1 m (6)

US Government US Army Corps of Engineers Above St. Marys Rapid Below Rapids 405 24 5.8 ~ 6.7 m

Niagara River

Beck 1 Ontario Power Generation CGIP above Niagara Falls Lower Niagara at Queenston 549 (14) 417 (14) 89.7 m (6)

Beck 2 Ontario Power Generation CGIP above Niagara Falls Lower Niagara at Queenston 1849 (14) 1499 (14) 90 m (6)

R.H. Moses New York Power Auth. CGIP above Niagara Falls Lower Niagara at Lewiston 2832 (13) 2755 (13) 83.5 ~ 96.5 m (13)

Welland Canal

Weirs 1, 2 and 3 Rankin Renewable Power Secondary after lockage use Welland Canal 23 (15) 6.4 (15) 11.5 m (15)

ND1 (DeCew Falls 1) Ontario Power Generation Lake Erie via Welland Canal Lake Ontario via 12-Mile Creek 38 (14) 23 (14) 82.4 m (6)

NF23 (DeCew Falls 2) Ontario Power Generation Lake Erie via Welland Canal Lake Ontario via 12-Mile Creek 193 (14) 144 (14) 86.8 m (6)

Heywood St. Catharines Hydro Secondary after DeCew Falls Lake Ontario 283 (12) 7.2 (12) 4.4 m (12)

Source: Compiled by Peter Yee, December 23, 2010 based on communications with hydropower operators.


C. Marginal Generation and Market Prices

At any one time, the electricity market clearing price and marginal emissions are determined by the

generation dispatch order and the current load level. In the Upper Great Lakes region, most of the

electricity is provided by nuclear and coal generation, but modest amounts of natural gas generation set

the prices in many peak hours.

The following graph shows the generation in MISO during the summers of 2009 and 2010.1 Coal and

nuclear account for almost 90% of the generation, while wind accounted for about 2% of the generation.

The next graph shows which fuel was on the margin, and thus setting the market price in MISO, during

the summer months of 2008-2010.2 Coal was on the margin about 80% of the time, which means that it

was setting the price during most of the off-peak hours and about half of the peak hours. Natural gas

generation was setting the market price for most of the remaining peak hours. Wind is never on the

margin because it is always a price taker.

1 Midwest ISO 2010 Summer Assessment Report, Market Analysis Department, Midwest ISO, October 20, 2010.

http://www.midwestiso.org/publish/Document/6a7e86_12bc0f1b440_-7f500a48324a?rev=1 2 Ibid.


A similar situation occurs in the winter, when coal generation is even more on the margin - ranging from

84% to 93%.3

Compared with MISO, New York has more natural gas generation, which often sets the marginal price in

the eastern portions. Coal predominates in the western area near the Niagara, as is indicated by the

lower prices there.4

In a planned move away from coal generation, Ontario now generates more electricity from natural gas

than coal.5 Thus natural gas is predominately the marginal fuel there. Electricity market prices in Ontario

are set in a semi-regulated manner and thus do not reflect gas prices as clearly as NYISO and MISO

electricity prices do.

In terms of current electricity prices, the cost of coal generation is the primary determinant for the off-peak

hours, extending some into the peak hours as well. The cost of natural gas generation sets the cost in

many of the peak hours—especially those with higher loads.

Implications

Barring major system changes, the cost of coal generation will determine the off-peak electricity prices for

the UGL region in the short term. While the price of coal is unlikely to change dramatically, emission

regulations will likely increase coal generation costs in the mid to long term. The biggest uncertainty lies

with GHG regulation, where a $10/st cost for CO2 would increase the cost of coal generation by

approximately $10/MWh. CO2 prices of $30/st and more could raise coal costs up to those of natural gas.

3 Midwest ISO 2010 Winter Assessment Report, Market Analysis Department, Midwest ISO, April 07, 2010.

http://www.midwestiso.org/publish/Document/15cf2f_128d94d853e_-7f500a48324a?rev=1 4 2009 State of the Market Report New York ISO, David Patton et al, Market Monitoring Unit for the New York ISO.

http://www.nyiso.com/public/webdocs/documents/market_advisor_reports/2009/NYISO_2009_SOM_Final.pdf 5 Ontario Reliability Outlook December 2009, Independent Electricity System Operator,

http://www.ieso.ca/imoweb/ircp/reliability_outlook.asp


Peak period prices, especially those in the higher load hours, will be set by the cost of natural gas

combined cycle generation. Current natural gas prices and future forecasts are at relatively low levels,

making efficient natural gas generation competitive with higher cost coal plants. However, natural gas

prices have shown considerable volatility and been higher in the past, and that could be the case again

especially when going out several decades. GHG regulation has a smaller impact on combined cycle

natural gas generation than on coal. A CO2 cost of $10/st would increase the cost of gas fired generation

by approximately half as much, or $5/MWh, as it would impact the price of coal fired generation.

The effects of renewable generation, likely to be predominately wind in the UGL region, complicates

analysis of market prices. Although it is increasingly predictable, wind is a variable resource and must be

used when available or lost. Much wind generation is likely to occur during the off-peak hours, pushing

out some coal and perhaps even moving prices towards zero in some hours. Since coal generation takes

a while to ramp up and down, faster ramping natural gas generation may have to be dispatched instead

to make up for differences in forecast wind generation and actual wind output. The precise impact of

renewable energy on energy prices is complicated and depends on many factors, but the net effect will be

a downward effect on wholesale electricity prices.


D. Historic Price Patterns

To provide some historic context for the price forecasts, energy prices going back about five decades

using EIA data were examined for this analysis.6 To show the basic patterns, the effects of inflation were

removed. The first graph shows retail electricity prices in constant US dollars. Recent prices are just

slightly above the long term average. Also important to note is that the wholesale energy cost is only a

little more than a third of the final customer cost. Thus, a doubling of the wholesale price would only

increase customer costs by about a third.

US Average Retail Electricity Prices in Constant Dollars

0

1

2

3

4

5

6

7

8

9

10

11

12

1960 1970 1980 1990 2000

20

05 c

/kW

h

xviii

The next graph shows the wellhead price for natural gas, which was flat until the mid 1970s and more

than quadrupled by the early 1980s. The price subsequently fell by 50% and stayed at that level until

2000. Over the last decade, it rose again, nearly tripling by 2005, and exhibited extreme volatility. In the

last two years, prices have fallen by more than 50% from the most recent highs. Current expectations,

reflected in the futures markets, are that gas prices will rise modestly above current lows but not

approach previous highs in the next few years.

6 EIA Annual Energy Review, http://www.eia.gov/aer/contents.html


US NG Wellhead Prices

0

1

2

3

4

5

6

7

8

1960 1970 1980 1990 2000

20

05

$ p

er

100

0c

f

xix

Historically, prices for coal, the baseload fuel for MISO and western NY, have been less volatile than gas

prices. Coal prices reached historic lows around the year 2000 but have since increased by about one

third. Part of the long-term price decline is associated with increases in Western coal production, which,

while lower in sulfur, is also lower in energy content.

US Coal Prices

0

10

20

30

40

50

60

70

1960 1970 1980 1990 2000

20

05

$/s

t

xx


E. Energy Price Forecasts

As indicated by the past, there is considerable uncertainty regarding fuel prices. One source of

information is the NYMEX futures market for HH natural gas, which reflects expectations that natural gas

prices will rise to the $5 level by 2013 and then stay relatively flat to 2023. Natural gas futures are shown

in the graph below. Market trading is very thin in the later years, so those prices should be viewed

skeptically. The next graph shows the electric generation fuel price forecasts for the ECAR region7 from

the 2010 Annual Electric Outlook through 2035. This graph shows natural gas prices nearly doubling

over 25 years but coal prices staying very flat.

HH NG Futures 12/21/10

0.00

1.00

2.00

3.00

4.00

5.00

6.00

2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023

2010

$/m

mB

tu

xxi

AEO 2010 ECAR Fuel Prices for Electric Generation

0.0

1.0

2.0

3.0

4.0

5.0

6.0

7.0

8.0

9.0

2010 2015 2020 2025 2030 2035

20

10

$/m

mB

tu

Natural Gas

Coal

xxii

7 AEO 2010, Table 72 Electric Power Projections for the EMM Region.


F. Forecast Uncertainty

Looking at the ability of previous price forecasts to predict actual market outcomes can shed light on how

much future price forecasts could deviate from reality. Taking a retrospective view of the accuracy of

energy forecasts can be difficult, as past forecasts are often difficult to find. However, the EIA has

collected and consolidated previous AEO forecasts and published a report comparing forecasts going

back to 1982.8

Focusing on electricity, the prime interest of this report, in mid-2008 AEO forecasted that the average US

electricity price in 2008 would be 9.82 cents/kWh. As shown in the graph below, AEO’s 1991 forecast of

2008 prices was 14.58 cents/kWh, almost 50% too high. The price of electricity declined in subsequent

forecasts, undershooting the mark in 1997 and then staying about 25% low for the next eight years.

Then, as the forecast year 2008 approached, the forecasts became more accurate, with AEO 2008

(actually produced in 2007) only 4% off the mark. Modeling and forecasting techniques have gotten more

sophisticated over time, but the further one goes out, the greater the uncertainty.

AEO Forecast Errors of the 2008 Average Electricity Price

-40%

-30%

-20%

-10%

0%

10%

20%

30%

40%

50%

60%

1991

1992

1993

1994

1995

1996

1997

1998

1999

2000

2001

2002

2003

2004

2005

2006

2007

2008

2009

xxiii

Nearly all forecasts end up being wrong to a greater or lesser degree, but most often energy price

forecasts err on the low side. Thus, the value of the UGL hydro generation in the future could be much

greater than the current forecasts indicate.

8 Annual Energy Outlook Retrospective Review: Evaluation of Projections in Past Editions (1982-2008), EIA, September

2008. http://www.eia.doe.gov/oiaf/analysispaper/retrospective/pdf/0640%282008%29.pdf


G. GHG Emissions Regulation

GHG emissions regulation and carbon prices likely to come out of those regulations are discussed

extensively in the Synapse 2008 report. Currently, an update of that report is being developed and will be

included as supplemental material to this report.

Hydropower Technical Work Group Peer Review Contribution · The three hydropower plants at Sault...

Documents

Transcript of Hydropower Technical Work Group Peer Review Contribution · The three hydropower plants at Sault...