Will the U.S. Allow the Natural Gas Bonanza?

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Each spring, Cambridge Energy Research Associates (CERA), part of consulting giant IHS, holds a week-long conference in Houston focused on worldwide energy markets: oil, gas, coal and electric power. As I drove toward downtown Houston, it was reminiscent of the 1978 boom days. Tall cranes are reshaping the city skyline once again. Local residents are discussing the overheated real estate market. Realtors advise buyers to bid high if they are serious about a purchase. The return of boom times can be summed up in one word: shale. And we owe it all to the legendary George P. Mitchell who passed away during July 2013.

Dan Yergin, founder of IHS CERA said Texas legend Mitchell was responsible for what is the most important innovation in world energy so far this century. Before his breakthrough, shale gas had another name — uneconomic gas. It was thought that there was no way to commercially extract it. Mitchell proved it could be done.

“His breakthrough in hydraulic fracturing, when combined with horizontal drilling, set off the revolution in unconventional oil and gas that we see today,” said Yergin. “It took a decade and a half of conviction, investment and dogged determination. In the face of great skepticism and refusing to accept “no” as an answer, Mitchell dramatically changed America’s energy position. As such, he also changed the world energy outlook in the 21st century and set in motion the global rebalancing of oil and gas that is now occurring.”

The U.S. is blessed with huge shale formations in Pennsylvania, Ohio, North Dakota and Texas. It has gone from a shortage of natural gas supply to such an abundance that LNG import terminals are being refitted to become LNG export terminals. But not so fast! The politics of energy, economics and public opinion continue to swirl. Is it wise to allow free market export of natural gas? Should we be building new pipelines to make the new gas supply more available to consumers and for export? Will we find ourselves with much higher gas prices and shortages after we squander the supply? Should we be sponsoring the growth of a carbon based energy economy in the face of global climate change? Should we be heavily taxing this new oil and gas production to prevent damage to the renewable energy industry?

While the U.S. oil and gas business is booming, consumption of electricity has been reduced in part by energy efficiency improvements in lighting and appliances and a loss of industrial demand. The electricity business in competitive regions of the U.S. is struggling to make ends meet. One approach being suggested is that generating companies should be provided with a guaranteed payment stream for providing capacity to supplement their revenues from electricity sales in a soft market. In addition, new power plants must be built to provide a path to retire older plants that have higher emissions and lower fuel efficiency.


So many questions, so few answers. Turbomachinery International asked Larry Makovich, HIS-CERA’s Vice President & Chief Power Strategist his thoughts on the electricity markets:

Q: Has the industrial renaissance discussed at CERA last year begun to boost the growth rate of electricity consumption in the U.S. closer to the 1.5% to 1.7% rate that you predicted?

A: The U.S. ended the year with less than 1.0% growth in electricity output. Keep in mind that 2012 had a record setting hot summer coupled with a GDP improvement of only 1.7% in 2013. But for the first 2 months of 2014, U.S. electricity consumption is up over 5%. The economy is growing at a stronger rate and there is evidence that the industrial renaissance is kicking in. If the U.S. has normal summer temperatures during 2014, we will consume more than 1.5% more electricity than in 2013.

Q: In most regions of the U.S. the ratio of peak demand to average demand is increasing. As the U.S. grid gets “peakier,” what responses do you think will evolve in the market?

A: During the last decade or so, the load factor of our power plants has been going down. If your goal was to match the load profile, you would want more GT peakers in the mix. Some expect that solar rooftop will reduce the need for more peak demand on the grid. But solar panels hit peak production around noon while electricity demand peaks at 6 p.m. So the dampening effect hoped for is not being achieved.

Q: The latest Brattle report suggests a 10% reserve margin is satisfactory for the ERCOT grid in Texas, far less than other regions are targeting. With advances in smart meters and demand response, will a 10% reserve margin become the new normal?

A: It is a mistake to believe that 10% is enough reserve margin. Richard Doying, Executive VP of Operations of Midcontinental ISO, and Terry Boston CEO PJM Interconnection, both concluded that a 10% reserve margin will result in a lack of reliability. The problem in Texas is that wholesale prices will not be high enough to increase the average price of electricity and incentivize new supply without creating a shortage. To my mind, it is a misdiagnosis of the problem and an ineffective remedy to allow the Texas system to go into shortage periodically. I don’t think people are going to be happy.

Q: Should old peaking plants or a demand response contract be paid the same price as a modern combined cycle plant?

A: There are some important differences. A 1 MW demand response contract also reduces the necessity for reserve margin on that 1 MW. So a megawatt of demand response is worth more than a megawatt of generation. You also must to take into account the reliability of the fuel supply. So not all capacity is created equal. They have different impacts on operation of the grid. Compensation for capacity needs to be aligned accordingly. We also need extra compensation for flexibility, quick start and spinning reserve capability.

Q: It was a tough winter in New York and New England but the gas and power supply made it through barely. Any lessons learned?

A: There are complicated challenges between how the natural gas pipeline system and the power grid are operated. There’s a misalignment between what we call a “gas day” and a “power day.” This is a coordination problem that must be resolved. Parts of the problem are gas deliverability and price volatility. This winter, we discovered that the value of dual-fuel capability is much larger than recognized, i.e., switching to oil when gas supply runs short. This capability acted as a safety valve in New England and came to the rescue.

Q: What does your crystal ball show for the California electricity market during the next few years?

A: Although California lacks choice and competition, it still relies on the marketplace to dispatch its generating resources. There is a resource adequacy requirement which creates a demand for capacity which is a start in the creation of a marketplace. Despite all of its renewable and efficiency efforts, the state’s CO2 emissions per kWh have been flat for a decade. With the closure of the San Onofre nuclear plant, we can expect to see its emissions go up for the next few years.

Q: What changes do you expect to see in the Entergy region now that it has become part of MISO? Will customers in LA-MS-AR feel any changes?

A: We saw a recent announcement about the close of the Kewaunee nuclear plant in Wisconsin because the market was paying only $40/MWh. The utility needed $55 to keep it going. MISO expects to be 2,000 MW short by 2016 with all the coal retirements. It will cost at least $70/MWh to replace the lost capacity. This is the same problem we see in other regions: power prices are chronically too low to attract new supply to be built and too many power plants are retiring before it is economically wise to do so.

Q: Any concluding remarks?

A: Let me share the story of electricity in Germany. They had well intentioned energy policy that didn’t take into account the complexity of a power system, or engineering and economic principles. Germany ended up with very expensive electricity. Forced retirements of nuclear plants have led to more coal-fired generation as renewables could not fill the gap. CO2 emissions have risen. The two largest investor owned utilities (EON and RWE) have lost about 80% of their value during the last five years. There are lessons to be gleaned in terms of U.S. EPA policies going forward.

Written by: Mark Axford