There’s more interest than ever in increasing coordination between the U.S. gas and electric sectors. Each market now depends more heavily on the other than ever. Yet significant hurdles remain, many stemming from fragmented and distinct regulatory regimes and deeply entrenched operating practices on both sides.
As nobody in Texas will soon forget, in February of this year freezing temperatures across the southern U.S. hammered energy markets and resulted in widespread and long-lasting blackouts across the Energy Reliability Council of Texas (ERCOT) power region. Life for many Texans came to a standstill for a week until power could be restored. The resulting economic damages have been estimated in the billions. Many people, rightfully, questioned how an energy-rich state like Texas could have been so affected. And then the blame-game started. Lacking a forum of qualified experts, productive discussions took a back seat to self-serving rhetoric, special-interest advocacy, and political posturing. But if real solutions were going to be found, it would take more than finger-pointing. It would take a meeting of experts whose primary focus was a resolution, rather than a constituency. Fortunately for Texans, that’s what they got two weeks ago. In today’s blog, we take you through the symposium and its outcome, particularly regarding the role of natural gas.
The “polar vortex” of 2014 dipped far south enough to impact power markets in Texas. On Monday January 6th, the Electric Reliability Council of Texas (ERCOT) came dangerously close to initiating rolling blackouts as power demand increased due to record low temperatures and unexpected generation unit outages. Real time electricity prices spiked to over $5,000/ Megawatt Hour (MWH). The close call served as a sobering reminder for Texas regulators of the ongoing debate over how the State will meet future power generation requirements. Today we detail the “polar vortex” event and explain the implications for Texas power.
Three North Dakota electric utility companies are adding close to 800 MW of new generating capacity in the next five years. Unlike 68 percent of the State’s current generating capacity that uses coal fuel, the new plants will be powered by locally produced natural gas. The plants are needed in part to meet growing demand for power from Williston Basin oil and gas field services and infrastructure. A 2012 study sponsored by the North Dakota Transmission Authority estimates that demand in 45 Williston Basin counties will increase by 90 percent or 1000 MW between 2012 and 2017. Today we review regional power demand from the oil and gas industry.
Last Friday (July 19th, 2013) temperatures in New York City rose to 100 degrees Fahrenheit for the second day in a row. At 4:00 PM that day the New York Independent System Operator (NYISO) recorded a new State record peak power demand of 33,956 MW. In New York City (known as “Zone J”) real time power prices jumped as high as $1485/MWh. Today we examine the power price volatility.
Growth in natural gas demand forecasts these days rely heavily on projections of increased power burn. Lack of coordination between the gas and electric industries threatens to limit that expansion. The greatest challenge is the security of gas supply to the generators and how that impacts reliability. Regional differences in the electric power market appear to make national regulations to secure gas supplies unworkable. Today we review FERC efforts to understand and perhaps attempt to standardize those regional differences.
During 2012 the FERC jumped into the ring to involve itself in the long running debate to improve coordination between the gas and electric power industries. The FERC is motivated by concerns about reliability and the trend to increase power generation from natural gas at the expense of coal and oil. The commission held 5 regional conferences to identify the industry’s concerns and the role of regulation in any solutions. Today we examine progress on this important initiative.
