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The November wholesale natural gas contract was lower by $.108 on Friday as the contradiction of weather anomalies was about to take place over the weekend. The Northeast was experiencing record highs and these highs should continue until midweek, Houston was experiencing much needed rain as 4 to 6 inches fall yesterday in a major area between Houston and the Dallas Fort Worth area. Snowfall also commenced in Colorado as several inches of snow fall in the mountainous area of Colorado. The 11-15 day forecasts continue to forecast normal to slightly above normal temperatures and this October should be slightly above normal as measured by heating demand. In the financial markets, it seems that job growth is staggering along per the employment figures while the North European countries are trying to finish discussions on how to help out the South European countries that are in seemingly dire straits.
In the lone star state this morning, A Standard and Poor’s report labeled “Texas’s Long, Hot Summer Makes Power Retailers Sweat” is out and claiming that inevitable shake-out in ERCOT's retail power market is slowly but surely underway as smaller players begin showing signs that operations are untenable. The crux of the S&P report, which is a good read, is that due to looming federal environmental regulations and what was an already tight supply-demand balance in ERCOT, "any major weather event would likely create significant spikes in power prices." Retailers without generation would be challenged to survive any prolonged and sustained wholesale volatility, S&P says, concluding that only retailers with generation are viable. That's a reasonable and defensible view of the market climate, but what isn't supported are statements from S&P that suggest this market shift and a "shakeout" in retail providers is already here. S&P correctly notes that August was essentially an ugly month for retail providers, and that its effects may linger with increased bad debt from higher customer usage, and higher forward curves for wholesale prices. However, the one company that had generation NRG had a misfortune of not structuring their strategic assets for their best use and applying their generation to serve their retail load and when prices spiked, they had to purchase incremental energy in the open market.
On the drilling front, the number of rigs drilling for natural gas in the United States climbed by 12 this week to a 9-1/2-month high of 935, data from oil services firm Baker Hughes showed on Friday. The gas-directed rig count is at its highest since Dec. 17, when the total stood at 941. The count is down 6 percent from its 2010 peak of 992, it’s highest since February 2009, when 1,018 rigs were drilling for gas. Horizontal rigs, the type most often used to extract oil or gas from shale gained 13 to a record high 1,148, eclipsing the previous record of 1,140 hit two weeks ago. U.S. Energy Information Administration data last week showed gross natural gas production in July in the lower 48 U.S. states climbed to another record high of 69.5 billion cubic feet per day. Record heat this summer triggered plenty of power demand, but energy traders said high gas production easily offset the surge in cooling needs and several storm-related supply cuts. The gas rig count of 935 remains well above the 800 level some analysts say is needed to cut production significantly and tighten overall supplies. Most analysts expect no major slowdown in domestic gas output until next year. The gas rig count is nearly 42 percent off its record peak of 1,606 from September 2008, and 36 rigs, or 4 percent, below the same week last year. Rising output from shale gas has been the primary driver of increased gas production in the last few years, and most traders agree it will be difficult to tighten the loose gas market unless horizontal gas drilling slows sharply. Without serious production cuts or a stronger economic recovery to boost industrial demand, which accounts for about 30 percent of gas consumption, few energy traders expect much upside in gas prices in the near term.
On the anti-innovation front, homeowners who sank thousands of dollars into solar power systems are hopping mad at San Diego Gas & Electric Co.'s proposal to charge them for using the electrical grid. On Monday, SDG&E filed a request to the California Public Utilities Commission that would allow it to separate how much it charges customers for electricity from how much it charges to transport that electricity. For traditional customers, the change would have little impact on their total bill. But solar customers would end up paying an average of $11 extra per month, according to a utility spokeswoman. When his solar panels produce a kilowatt-hour during the day that he doesn't use, the utility credits him for a kilowatt-hour he uses at night, when his panels are dormant. For many solar customers, net metering can lead to dramatically lower electric bills, and often a bill close to zero. But in SDG&E's view, this means those customers aren't paying for the work the utility does to maintain its grid. Solar customers produce electricity, which the utility buys; but they also use the lines, whether to draw power in at night, or to pump it out during the day, said J.C. Thomas, SDG&E's manager for government and regulatory affairs, in an interview last week. Under current rates, non-solar-power customers are covering the expense of the grid for solar customers, Thomas said. By SDG&E's calculations, an average solar-power customer receives an $1,100 subsidy from SDGE's 1.4 million customers, or a total of $15 million a year.
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