Unlocking Electricity Prices:

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1 Volume 2 A BidURenergy White Paper Unlocking Electricity Prices: A White Paper Exploring Price Determinants by: Mark Bookhagen, CEP

2 pg. 2 Written by Mark Bookhagen, CEP Introduction In order to be classified as a commodity, a good or service must be homogenous. Electricity meets this criterion, but it has a unique characteristic. It cannot be economically stored in the same manner as other commodities can be stored like, say, corn in warehouse. This characteristic creates a situation where instantaneous supply must always equal instantaneous demand to provide safe and reliable electric service to energy users. The differentiating characteristic of electricity lends itself perfectly to a stacked bid auction in which multiple generators bids are accepted until 100 percent (plus a reserve margin) of demand is met, and all generators are paid the price of the last (highest) bid accepted. This BidURenergy Energy White Paper is in response to the concerns of many, otherwise sophisticated, commercial and industrial procurement managers who are not fully conscious of electricity price determinants and drivers. Most appreciate the fact that the generator s primary input (fuel) is extremely important to electricity pricing, but there is confusion over which fuel is the primary marginal cost driver I and why. Generation in the United States The generation of electricity requires fuel, and generation plants are usually built to burn one fuel type to create electricity. The differences in generation plants are mainly attributable to the fuel source used. There are specific advantages and disadvantages to each generation fuel type. Examples: Renewables (solar, wind, biomass, etc.) have a zero fuel cost, but are extremely inflexible (the sun shines when it shines; the wind blows when it blows; no one can control the amount of fuel available). Hydroelectric dams are flexible and have zero cost fuel, but they are expensive to erect, must be placed in a waterway, and disrupt the ecosystem. Natural gas is the lowest CO 2 emitting fossil fuel. These generation resources can be deployed within hours (flexible), but the fuel cost is relatively high. Coal is inexpensive, but its impact on the environment is extremely high. Nuclear power is moderately inexpensive, but it has issues with spent fuel storage, high capital costs, high maintenance costs, safety issues, and flexibility (taking days to power up or down).

3 pg. 3 A summary table is shown in Figure 2 below: Characteristics of Generation Sources Fuel Type Flexibility Initial Capital Costs Maintenance Cost Fuel Cost Environmental Impact Renewables Low Low Free Low Hydro Free Nuclear Low Coal Low Natural Gas * *See The Future section below regarding natural gas prices Figure 1 Of the nearly 11 million megawatt-hours of electricity generated on an average day in the United States, 67.9% (See Figure 1, 2012) of the output is fueled by two sources - coal (37.6%) and natural gas (30.3%). Even with the tightening of CO 2 emissions standards and the promise of further tightening by federal and state governments, coal is clearly the most used electricity generation fuel. Since coal is the most used fuel, it is logical to assume that the price of coal should have the largest impact on the price of electricity. After all, this is how pricing is set for normal commodities II. For example, if corn was primarily grown using fertilizer (on a percentage of cost basis), a person purchasing corn should have the price of fertilizer in the #1 position on his Inputs to Watch List. This is where the misconception of many purchasing managers comes into play. They reason, If coal is the most used fuel, then my primary concern when predicting electricity s price direction is coal s price direction. Although this reasoning is perfectly logical, it ignores electricity-pricing dynamics. We will need to explore a few more key principles before explaining this concept further. For now, it is only necessary to realize that coal is NOT #1 on the Inputs to Watch List.

4 pg. 4 U.S. Electricity Generation by Fuel, All Sectors 14,000 THOUSAND MEGAWATTHOURS PER DAY 12,000 10,000 8,000 6,000 4,000 2,000 Forecast 49.6% 49. 0% 48.5% 48.2% 44.4% 44.8% 42.3% 37.6% 39.0% 39.6% 18.8% 20.1% 21.6% 21.4% 23.3% 23.9% 24.7% 30.3% 27.9% 27.5% Coal Natural Gas Petroleum Nuclear Hydropower Renewables Other Sources Note: Labels show percentage share of total generation provided by coal and natural gas. Source: Short-Term Energy Outlook, January 2013 Figure 2 III How are Generators Dispatched? A power-using device cannot decipher the source of its power because an electron pushed through the transmission system from a solar farm to the device is identical to an electron pushed through the transmission system from a coal plant to a device (remember the definition of a commodity). Since all electrons are created equal, it is logical to deploy a low cost generation unit before a high cost unit since power quality is identical. Deploying the lowest cost generator first is known as the least-cost method.

5 pg. 5 Central governing bodies (e.g. PJM Interconnection, ERCOT, NYISO, NE-ISO) are responsible for coordinating and dispatching power using the aforementioned least-cost method. Electricity generators bid into the electricity market on, at minimum, a daily basis to sell their power for each hour of the next day (Day-Ahead Market). Bids are accepted (a.k.a. generators dispatched) until demand is met in a bid stack format (See Figure 3). Bid stacking is an auction format used to implement the least-cost methodology. From a generator s point of view, their bid must cover their cost of goods sold. The marginal cost of producing electricity is the marginal cost of the fuel used to generate the last MW needed to meet the grid s demand. Ceteris paribus, a coal plant will submit low bids so long as the cost of coal remains low. A hydroelectric power plant will also submit low bids because its fuel (water) is virtually free, and its output is only limited by the plant s generation output capacity. Solar farms, wind farms, and other renewable generation owners will submit equally low bids because their fuel is also free, and if they do not sell the power when it is generated, it will go to waste. Remember, electricity cannot be economically stored. In the case of renewable sources, the fuel cannot be stored either! This means the generator will take almost any price they can get for their outputted power, but will always be paid the bid ($/MW) of the last MW needed to satisfy Day-Ahead demand. Generation facilities with low (or non-existent) fuel costs and the ability to output a steady stream of power form the electric grid s baseload. The baseload is the minimum amount of power needed to meet the demand of the electricity grid. Put differently, it is the minimum amount of electricity needed during an entire day, which means baseload generation plants rarely power down. Grid baseload demands are typically met by the inexpensively fueled (hydro, nuclear, and coal) generators because their marginal costs of output are lower than natural gas plants (refer back to Figure 2 for relative cost data by fuel type). Renewables like wind and solar are not considered part of the baseload because they are intermittent; they are, however, price takers (i.e. they submit low bids and hope for a high clearing price). The least-cost generators are dispatched first. Then, the more expensive fueled peaker plants are dispatched. Peaker plants meet the residual demand (i.e. the peak load) after the baseload resources have been dispatched. Natural gas usually fuels peaker plants in the U.S. IV

6 pg. 6 Traditional Dispatch Schedule Example #1 Figure 3 shows each generation fuel type and its associated bid. On an average day (vertical purple line), a natural gas plant supplies the last MW needed to meet the required demand (~38,000 MW). Since the market operates in using a stacked bid format, all generators are paid the amount that corresponds to the last bid accepted (~$40.00/MW) even though they may have bid a lower rate. This has drastic implications! Each generator will bid to generate until marginal cost equals marginal revenue or until they have bid their entire output capability (capacity). On an average day (from Figure 3), the coal generator will likely be able to sell its entire capacity and will always be paid the price of the last accepted bid. Generation owners will not bid arbitrarily high because there is no upside to doing so in this competitive market. To maximize profit, generators supply megawatts until marginal cost equals marginal revenue. Again, remember that the marginal cost for a generator is determined by price of the fuel used to generate. Hypothetical Supply Stack Dispatch Cost $/MWh (Fuel + VOM) Water Coal Gas Uranium Oil Other Peak Demand Average Demand ,000 20,000 30,000 40,000 50,000 60,000 70,000 80,000 Comulative Capacity MW Figure 3

7 pg. 7 Traditional Dispatch Schedule Example #2 Figure 4 shows a hypothetical dispatching schedule. The same principles apply as did in Figure 3, but they are portrayed on a smaller scale and in a different format. Bids for 06:00-07:00 EST Where Demand = 50 MW Generator Name Quantity Available (MW) Bid ($/MW) Quantity Cumulative MW Supplied / Not- Amount paid to Generator by Customers ($/MW) Solar Farm #1 4 $ Solar Farm #2 2 $ Wind Farm #1 6 $ Nuclear Plant #1 12 $ Coal Plant #1 10 $ Coal Plant #2 3 $ Coal Plant #3 5 $ Natural Gas Plant #1 5 $ Natural Gas Plant # Partially Natural Gas Plant #3 7 $ Not- $0.00 Total Figure 4 Natural Gas Plant #2 is the marginal generation plant needed to meet the 50 MW demand. Its bid of /MW was accepted, and all generators are paid /MW for their designated output. Natural Gas Plant #3 does not produce any power and is not paid during the 06:00 07:00 EST auction period.

8 pg. 8 What is THE Key? The price of the last (a.k.a. marginal) dispatched generation unit s fuel is the key to unlocking electricity prices. For the better part of the last 20 years (save extremely recent trends related to shale gas and hydraulic fracturing), natural gas generation plants have been THE last unit dispatched. Therefore, the price of natural gas has more often than not been the key determinant of the price of electricity. The next time your energy consultant mentions natural gas prices when you thought you were talking about electricity prices, you will know that she was referencing electricity pricing s dependency upon natural gas s price. With a basic understanding of how electric generators are dispatched, one can appreciate the impact of natural gas prices on electricity prices. The U.S. Energy Information Administration (EIA) recognizes this conclusion. In Regional Transmission Organizations (RTOs), the price of the marginal generator, and thus the fuel it uses (the marginal fuel) is a key determinant of the price of electricity V Supporting Evidence According to a Federal Energy Regulatory Commission (FERC) study VI (2005, Yoo & Merony), the correlation between natural gas pricing and electricity pricing is relatively strong. The R 2 values VII for NE-ISO, PJM Interconnection, and NYISO were 0.71, 0.63, and 0.74, respectively during the period analyzed VIII. According to an EIA projection (Dec. 2012) IX, Following the recent rapid decline of natural gas prices, real average delivered electricity prices in the AEO2013 Reference case fall from 9.9 cents per kilowatt-hour in 2011 to as low as 9.2 cents per kilowatt-hour in 2015, as natural gas prices remain relatively low. Retail electricity prices are influenced by fuel prices, particularly natural gas prices.

9 pg. 9 Application x Customers billed based on actual time-of-use (a.k.a. interval billed) are able to adjust their energy usage schedule to account for then-current prices. During normal business hours (peak hours), natural gas will be the key determinant because it will be the marginal fuel used to meet the required demand. During off-peak hours, coal will likely be the key determinant because a coal-burning plant will likely be the last unit dispatched; thus, coal will be the marginal cost driver. Depending on when the majority of a facility s power is used or if a schedule modification is possible, the #1 Input to Watch (marginal fuel) may be different. For a typical customer, the peak hours of the grid will be similar to the peak hours of the customer s facility, which means natural gas will be the key influencer of the customer s electric supply rate. In states using market based pricing structures (e.g. New York), customers who are not interval metered are assigned a load profile by their utility. These load profiles weight electricity used (kwh) in a way that mirrors that of a typical customer. The easiest way to understand this concept is through an example. Consider a customer who used 200 kwhs in one day. They may be assigned to a load profile class and billed in a manner similar to that of Figure 5. As seen in Figure 5, the 200 kwhs used throughout the example day are distributed according to the weight (column B) for that time and multiplied by the market price at that time. In this example, the customer is assumed to have used 10.0% of his power during the 12:00 hour, 6.0% in the 17:00 hour, and during the 23:00 hour. The assigned load profile may or may not be accurate for that particular customer, but it is the utility s best guess and is based on the sample load profiles of like-customers. For customers billed in this manner (i.e. when the electric meter does not account for when power is used throughout the day), the primary marginal cost driver (fuel) will be natural gas because the majority of the $19.03 was billed during the peak hours when natural gas generators are the last unit dispatched setting the price for the market.

10 pg. 10 A B C (Total kwh x B) D E (CxD) Hour Beginning Weight Applied kwh used Price at time ($/kwh) Cost to Customer 0:00 1:00 2:00 $0.034 $ :00 $0.044 $ :00 1.0% 2.00 $0.050 $ :00 1.0% 2.00 $0.057 $ :00 2.0% 4.00 $0.060 $ :00 4.0% 8.00 $0.079 $ :00 5.0% $0.066 $ :00 5.0% $0.081 $ :00 6.0% $0.095 $ :00 9.0% $0.094 $ : % $0.110 $ : % $0.105 $ : % $0.140 $ : % $0.130 $ :00 8.0% $0.090 $ :00 6.0% $0.080 $ :00 3.0% 6.00 $0.060 $ :00 3.0% 6.00 $0.055 $ :00 1.5% 3.00 $0.044 $ :00 $0.034 $ :00 23:00 Total 100.0% 200 $ Figure 5

11 pg. 11 The Future If current natural gas supply trends continue and prices remain near record lows, the last generation fuel type dispatched may change. At current prices, the fuel next in line (second last unit dispatched) is coal. Under these circumstances, coal would become #1 on the Inputs to Watch List during off and on-peak hours. Until that change occurs, natural gas prices will dictate the direction of electricity markets. I II III IV V VI VII VIII IX X The primary marginal cost driver is the input with the greatest effect on the marginal cost of an output. Throughout this paper, it is assumed that quantity demanded is given and cannot be altered. (p. 77) The closer the R2 value is to, the strong the relationship of the variables is said to be. Periods analyzed: NE-ISO & PJM ; NYISO The conclusions within this paper assume a standard load profile in which a customer uses his power throughout the day in the same manner that the grid uses. About BidURenergy, Inc. - is an electricity and natural gas consulting firm with thousands of clients across the nation, specializing in energy procurement auction administration. The firm s services are available to industrial, commercial, and retail companies. For more information please visit

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