The Power Connection

Transcription

1 AMEREXENERGYUPDATE ELECTRICITY / NATURAL GAS / PETROLEUM / COAL The Power Connection MAY 2007 / VOLUME 3, ISSUE 9 IN THIS ISSUE: TWO ERCOT VS. PJM: VARIATIONS OF A COMMON THEME SIX Natural Gas Outlook Crude Outlook SEVEN Gas Storage Outlook Electricity and Coal Outlook EIGHT ERCOT Energy Prices How Important is Data? The data below, is a just a small sample of the daily distribution from our wholesale power desk. The sheet provides Heat Rates for different locations and tenors. Whether truing up quotes from different Retail Electric Providers or working on a pricing proposal for a client, the ability to know where the market is priced (and when a quote or assumption is in error) enables meaningful decisions and the ultimate objective of any plan, the ability to execute. You might ask why Heat Rates? Why not the power price? The answer is we do provide those as well, but the most transparent and most accepted norm in power pricing is NYMEX (Henry Hub HH) natural gas prices X Heat Rate. The more obscure (and oft times purposefully so) value is the multiplier, i.e., the Heat Rate. Effectively managing positions by securing a Heat Rate and calling natural gas locks opportunistically has been proven in ERCOT and this risk management approach is making its way to PJM and beyond. The forward curve is almost always the beast to be tamed and by knowing where the market is, you can concentrate on this curve. If you leave more than one component floating (natural gas and Heat Rate, whether as a block price or separated), you will necessarily need to make more than one decision (you may be 100% right in one curve s direction and blow the other one, resulting in a bad price). The simultaneous locking of both is your prime objective when the values are intrinsically good, but recent history has shown the market is reluctant to make pricing this easy, so you ll need to work for better pricing. Data such as this will prove to be one of the most important tools at your disposal. Use it. Please visit for a free trial!

2 ERCOT vs. PJM: Variations of a Common Theme If you ever have the opportunity to visit a wholesale power brokerage floor, by all means make it a priority on your schedule. While you re there, think about what s going on. Admittedly, the open outcry and associated intensity from the various brokers is entertaining in a mob frenzy sort of way, but what are they communicating? Most often, price discovery as defined in dollars per MW. This makes sense and is as most would probably expect. Sometimes, however (and the practice is growing), you hear queries about where such and such strip of natural gas is bid or offered and where the Heat Rate is. The pricing structure of ER- COT is dependent on the multiplication of the average price for natural gas by the appropriate Heat Rate. This isn t unusual; It s even expected. The surprising thing is that you re hearing the same thing in the PJM pit. The practice of legging the price of power with the feedstock side (natural gas) and the multiplier (Heat Rate) came about by establishing a bilateral Heat Rate that can be traded. Instead of taking the price of power and dividing by the average of natural gas prices to calculate an implied HR, you can now have an agreed-upon HR value with your trading counterparty. This value is trued up by the comparison of the resulting price vs. what the wholesale power market offers (if the price of HR X natural gas varies to such a degree as to offer an arbitrage with the power pricing, the true up will verify the initial price discovery). See example below: On April 4, 2007, Western Hub PJM price for peak power, June 2007, is bid/75.85 offered. The last trade was at The NYMEX quote for the April 2007 natural gas contract is 7.64 bid/7.66 offered. The last trade is The block Heat Rate quote is 9.85bid/10.05 offered, with the last trade at The implied Heat Rate if you calculate the last trade of power (75.75) divided by the last trade on NYMEX (7.65) is 75.75/7.65 = If you could buy the bid side of both HR and NYMEX natural gas (9.85 and 7.64, respectively), you would capture a power price of 9.85 X 7.64, or If you bought the offer sides (10.05 and 7.66, respectively), your power price would be about 77. The spread is bid/77 offered if you go the HR X natural gas route, and, when compared to the power bid/offer originally quoted at 75.60/75.85, yields the possibility of improving on the bid by.35 cents/mw and on the offer by 1.15/MW. Trader s books are made by spreads offering this kind of arbitrage and it keeps the market honest. O.K., you ve agreed to a wholesale price of power for PJM. Curiosity compels you to see what would be a corresponding price in ERCOT. You notice that the HR for peak June ERCOT is 10.55bid/10.62 offered, slightly higher than the value in PJM. The premium paid in ERCOT most likely has to do with (1) the relatively limited feedstock mix available (Texas must lean on natural gas for any meaningful incremental generation while PJM has more latitude and alternatives) and (2) the degree day risk premium is more acute in Texas summer heat.

3 ERCOT vs. PJM: Variations of a Common Theme cont... The transformation to retail power pricing is the next area of comparison. The ERCOT side of things lists the following: Shape (how much is the provider going to charge you for disposing of the portion of the wholesale block you don t use? this will be more expensive with wide swings of usage and more economic with flatter usage) Losses (how much electricity is lost to heat from transmission line resistance?) ERCOT bucket (ancillaries and the fees and assessments payable to ERCOT that finance reliable delivery from the grid along with the cost of imbalances NOTE: imbalances are sometimes included in the margin) Margin (how much are you paying to the provider and broker/consultant to manage your power procurement) The PJM side of things isn t that different. The losses are formulaic just as in ERCOT (it s a physics calculation based on the transmission level) and the shape will be handled in a similar manner (NOTE: some providers in both jurisdictions price shape through the HR/multiplier. It s not as transparent in this writer s opinion but certainly legitimate AND it can be verified by backing out the cost of the wholesale block and evaluating the remaining multiplier piece). The ancillaries and fees are similar as is the margin. What remains is the capacity element. The definitions of capacity are many and different. The criticality (which is the driving force as to how it s priced) is well described in the following excerpt: In an electricity market with a power-pool structure, total generation capability and forecasted demand are the critical factors for generators attempting to strategically bid into the market or to exert their market power. Some power plants might be under their maintenance schedule and/or forced outage. Electricity demand generally increases during the high-temperature days. To diagnose, in advance, the existence of market conditions under which generators are able to exercise their market power, a forecasted demand and total available supply ratio is proposed as a possible index to indicate such conditions. This approach doesn t speak to price, but price is what drives the adequacy of generation. The reserving of that space of a finite amount of generation is purchased. In ERCOT, the Heat Rate reflects this cost. In PJM, the same is true but the way it s developed is not. The value of capacity in PJM is determined by auction. The owners of generation assets monetize their capacity through such auctions and the providers can include such cost in their proffered Heat Rate (or fixed price). The window of this capacity lock is currently about 5 years in PJM. By way of comparison, ERCOT can lock in Heat Rate (thus insuring capacity) out as far as The fluctuation of this PJM capacity price is not foreign to ERCOT. We have seen values jump by over the last several months, dues in no small part to concern of adequacy of generation and the chosen path to lay that risk to the open market through the provider. The chart below depicts the Heat Rate value for June PJM peak power for the last year:

4 ERCOT vs. PJM: Variations of a Common Theme cont... June 2007 PJM Peak Power Heat Rate Heat Rate Days (Beginning April 4, 2006) Is there a correlation to ERCOT s Heat Rates? As the chart below illustrates, the direction is the same: UP! On Peak Heat Rates - ERCOT 1 Year Forward Calendar Strip Heat Rate Days (Beginning November 18, 2005) The ability to use this analytical information in Texas has led to the managed account approach. The ability to defer the locking of natural gas after setting the Heat Rate allows a longer look at the forward curve. Throw in the ability to move in and out of pricing venues (go into the real time market when pricing advantages tell you to and back out when price certainty no floating surprises is the choice), and a customized portfolio of power procurement is obtainable. Does the real time market in PJM equate to ERCOT as well? Early indications are that there are similarities and differences that require better understanding, but overall the outlook is promising. The pricing patterns in ERCOT provide the following chart...

5 ERCOT vs. PJM: Variations of a Common Theme cont... Daily Comparison of ERCOT Power Pricing Dollars/MWh $ $ $ $ $ $ $ $ $ $ $ $90.00 $80.00 $70.00 $60.00 $50.00 $40.00 $30.00 $ MCPE Ho ust on Daily Average MCPE Monthly Average Fixed Price Calendar Strip - Daily Days (Beginning October 1, 2004)...that tracks fairly well with the patterns found in PJM, below: PJM Price Comparison: Peak Fixed Price (Rolling 12 Month strip) vs. Real Time (Monthly Average) PJM 12 month Rolling Strip Dollars/MW Real Time Daily Pricing (Monthly Average) PJM Average Fixed Price 50 Real Time Pricing Average Days (Beginning March, 2005) The development of a malleable pricing platform will allow the latitude of decisions and action to expand in PJM just as it has in ERCOT. There are certainly some unique issues (PJM capacity auctions, city gate delivery, idiosyncrasies of LMP Real Time pricing, to name a few), but none that will prevent implementing some form of managed program IF the providers will work together in coming up with some rules of the road. One provider has already begun working on this and our expectations are for the majority of industry players to follow suit. The key to going forward is developing a repetitive formula for the multiplier (a.k.a., Heat Rate) and this is the focal point of efforts AND being able to distinguish the energy financial cost from the energy operational cost. Once the gas index piece is in place, the feasibility of moving in and out of the real time market will guide the overall strategy.

6 The Henry Hub natural gas spot price is expected to average $7.84 per mcf in 2007, 90 cents above the 2006 average, and $8.16 per mcf in Natural Gas Outlook Colder weather through the first 4 months of the year compared with last year (13 percent more heating degree-days) has prompted a rise in expectations for total natural gas consumption in Total consumption was up more than 10 percent in the first quarter of 2007 compared with the same period last year. In annual terms, natural gas consumption is expected to rise by 3.4 percent in 2007 and by 0.9 percent in Sustained high rig counts and the startup of the Independence Hub natural gas system contribute to expected growth in total U.S. dry natural gas production. With gains coming primarily in the onshore region of the lower-48 States, dry natural gas production increased by 1.3 percent year-over-year in the first quarter of On an annual basis, total dry natural gas production is projected to increase by 0.9 percent this year and 1.4 percent next year. Imports of liquefied natural gas (LNG) are estimated to have reached 180 billion cubic feet (bcf) in the first quarter, more than 60 percent above the corresponding period last year. LNG shipments are projected to remain strong throughout the forecast period, reaching 790 bcf in 2007 and more than 1,000 bcf in Higher U.S. prices relative to those in other LNG-consuming countries have spurred the recent surge in LNG imports and should continue to drive growth in the near term. Support from colder-than-normal weather in April (heating-degreedays were 14 percent above normal) pushed the average Henry Hub natural gas spot price from an average of $7.32 per mcf in March to an April average of $7.83 per mcf. Despite the recent surge, prices are expected to dip in May before rising over the next several months. The Henry Hub natural gas spot price is expected to average $7.84 per mcf in 2007, 90 cents above the 2006 average, and $8.16 per mcf in Crude Outlook The average price of gasoline for the summer driving season (April September) is projected to be $2.95 per gallon, up 11 cents per gallon from last summer s average. WTI crude oil spot prices are projected to average $64.27 per barrel in 2007, down from $66.02 in In 2008, WTI spot prices are projected to decline slightly to an average of $63.83 per barrel. The price of WTI is not, at this time, a reliable benchmark for average U.S. and other world crude oil prices (for further explanation see EIA s This Week in Petroleum, May 2, 2007). An alternative benchmark, the refiner average crude oil acquisition cost (RAC) (the volume-weighted average price of all crude oils processed by U.S. refineries) is projected to average $60.18 per barrel in 2007, a decrease of just 5 cents from the 2006 average, and $59.30 per barrel in The combined effects of the recent rise in crude oil prices, persistent refinery outages, and seasonal demand growth are expected to push monthly regular grade motor gasoline prices from $2.24 per gallon in January to $3.01 per gallon in May. EIA expects the gasoline price could then ease slightly before returning to the May level in August, as gasoline inventories remain low and the hurricane season approaches. As a result, the average price of gasoline for the summer driving season (April September) is projected to be $2.95 per gallon, up 11 cents per gallon from last summer s average.

7 Gas Storage Outlook ENERGYUPDATE... Working gas in storage was 1,747 Bcf as of Friday, May 4, 2007, according to EIA estimates. This represents a net increase of 96 Bcf from the previous week. Stocks were 230 Bcf less than last year at this time and 297 Bcf above the 5-year average of 1,450 Bcf. In the East Region, stocks were 83 Bcf above the 5-year average following net injections of 61 Bcf. Stocks in the Producing Region were 166 Bcf above the 5-year average of 529 Bcf after a net injection of 23 Bcf. Stocks in the West Region were 49 Bcf above the 5-year average after a net addition of 12 Bcf. At 1,747 Bcf, total working gas is within the 5- Working Gas in Underground Storage Compared with 5-Year Range Note: The shaded area indicates the range between the historical minimum and maximum values for the weekly series from 2002 through Source: Form EIA-912, "Weekly Underground Natural Gas Storage Report." The dashed vertical lines indicate current and year-ago weekly periods. Electricity & Coal Outlook Those regions with States undergoing market restructuring may experience more price volatility. Preliminary estimates show that February residential electricity consumption was nearly 17 percent higher than in the same month last year due to colder temperatures. However, an assumed return to normal summer temperatures should keep total U.S. electricity consumption growing at a relatively normal rate of 1.5 percent this year and 1.9 percent in Residential electricity prices are expected to increase at a rate of 2.6 percent during 2007, a growth rate close to the 2.2 percent average over the last 10 years. Those regions with States undergoing market restructuring may experience more price volatility. For example, residential prices in the East North Central region are projected to rise by nearly 6 percent in 2007, compared to the last 10-year average of only 1 percent. During 2008, average U.S. residential prices are expected to rise by 2.8 percent. Coal consumption by the electric power sector, which makes up about 92 percent of total coal consumption, fell by 1.1 percent in 2006, the first decrease in consumption since Projected growth in electricity demand should raise electricpower-sector coal consumption over the forecast period. Consumption in the electric power sector is expected to grow by 1.4 percent in 2007 and 2.0 percent in U.S. coal production, which increased by 2.6 percent in 2006 while total coal consumption declined by 1.0 percent, is expected to fall by 2.9 percent in 2007 but recover in 2008 (up 1.4 percent). Western coal production, which represents just over half of total domestic coal production, is expected to grow by 1.6 percent in 2007 and by an additional 1.4 percent in 2008.

8 ERCOT Energy Prices YEAR Balance of (Peak - 5X16; All - 7X24) 5X16 7X24 5X16 7X24 5X16 7X24 5X16 7X24 5X16 7X24 ERCOT Heat Rate X Gas Strip* Heat Rate 9.28X X X X X X X X X X7.89 NAT GAS STRIP Date: 5/8/2007 *Heat Rate X Gas Strip - Provided as an indication of price levels only; Calculated using median of STP HR Bid/Offer This data consists of purely indicative bid/offer market prices, and calculated heat rates where noted, and no warranty that the data represents or indicates prices at which transactions may be or were affected at any time is given by Amerex. Any opinion expressed or assumption made in association with the data is a reflection of the judgment of Amerex or any person who supplies all or part of the data to Amerex at the time of compiling the data and is subject to change without notice. Amerex Energy Services One Sugar Creek Center Blvd Ste. 700 Sugar Land, Texas (t) (f) (toll free) info@amerexenergy.com Notice of Proprietary Rights The information contained in this document is provided as a courtesy by Amerex Brokers LLC ( Amerex ). As a condition of receiving this information, you and any other recipient are deemed by Amerex to have acknowledged and agreed that (a) Amerex has exclusive and valuable property rights in this information, (b) Amerex is making this information available to a restricted group of recipients including certain of its employees, customers and business partners, and you may not distribute it in any form to any other person or entity without the express written consent of Amerex, and (c) you may make use of this information only for your internal business purposes and not for the benefit of any third party. Amerex does not make any representations or warranties, express or implied, with respect to any information contained herein, including without limitation any representation or warranty that the data set forth herein is accurate, complete or timely. Amerex reserves the right to terminate the distribution of this information at any time at its sole discretion.