Can the natural gas supply support these needs?
By Ross Baldick
There are several reasons to embrace the natural-gas-fired generation of electricity, including relatively low emissions compared to coal and oil and the cost-effectiveness of building and operating new plants that can be utilized in cogeneration configurations. At my school, the University of Texas at Austin, we have generated electricity on campus at our own combined-cycle plants for decades. Furthermore, the campus’s need for low-grade heat utilizes a greater fraction of the primary input energy than is possible with stand-alone combined-cycle plants used just for electricity production. That is, cogeneration reduces air emissions and decreases the amount of fuel used per unit of utilized energy compared to a stand-alone combined-cycle configuration without use of waste heat. Such cogeneration options are realistically only possible with smaller generation stations that are typically natural-gas fired since larger coal, oil, and nuclear generators can rarely be scaled for a waste heat use and are typically not suitable for urban environments.
Hydraulic fracturing in North America has greatly expanded the potential supply of natural gas. In general, natural gas has become relatively inexpensive in regions that have allowed hydraulic fracturing, and average natural gas prices are likely to stay low for the foreseeable future. Extended periods of moderate and stable natural gas prices will further encourage the demand for natural gas, which will result in a resurgence of its use in manufacturing and electricity generation. However, not all regions of the United States (or all countries) are willing to utilize hydraulic fracturing. Moreover, U.S. natural gas prices have recently increased, and there can be occasional interruptions to the natural gas supply due to weather or other events, resulting in price volatility during these periods. Consequently, the desire to diversify energy supply among resources could also result in some future expansion of nongas resources or the addition of dual-fuel capability to generators that use natural gas as their primary fuel.
Natural-gas-fired generation can be designed and tuned to meet operational flexibility requirements. This ability to provide both fast start-up and ramping facilitates the integration of intermittent renewable energy resources into the electric system. This combination of resources also reduces air emissions compared to a thermal-only portfolio and will encourage the further expansion of natural-gas-fired generation capacity as a complement to intermittent renewables. The increase in natural-gas-fired capacity and the associated increase in natural gas consumption will result in natural gas being an ever-more major player in thermal generation portfolios.
To utilize the flexibility of natural-gas-fired generation, however, gas supply must also be relatively flexible, and the gas infrastructure must support these needs. The flexibility and availability of natural gas supply is the focus of my concerns in this ìIn My Viewî column. Flexible resources and fuel supplies will be required to meet increases in intermittent renewable capacity and the resulting greater variability and uncertainty of the net load, which is the difference between the gross load and the intermittent renewable production.
To understand why the flexibility of the gas supply is a concern, first consider the case without intermittent renewables. In the absence of large-scale storage, the system generation must supply the instantaneous load at every moment. Demand levels are critically tied to ambient temperature and other weather-related variables. The availability of high-quality weather forecasts, together with modern statistical and forecasting techniques, has allowed for the very accurate forecasting of electrical and gas demand. The day-ahead forecasts of electric load are generally quite accurate. Consequently, in the absence of significant variable generation, the need for natural gas supply for electric generation can usually be well judged for day-ahead electricity markets. Natural gas markets have liquid trading opportunities within this day-ahead context, at least for Tuesday through Saturday delivery. However, the timing of these markets is not well aligned with the timing of various electricity markets, and the absence of liquid weekend trading means that most, if not all, deliveries for Sunday, Monday, and public holidays are established on Fridays. There is a mismatch between the ìelectric dayî (midnight to midnight, prevailing time) and the ìgas dayî (9 a.m. to 9 a.m., Central time). That is, nominating gas for the day-ahead electricity market involves nomination in two gas days, and the first of these two gas days begins before the clearing of the day-ahead electricity market. While the value of coordination between gas and electricity is fairly clear, there have also been concerns about sharing information between gas pipeline operators and independent system operators (ISOs) that could have helped to better coordinate gas and electricity operations. This is particularly vital for responding to contingencies on either the electric or the natural gas systems.
Nevertheless, natural gas markets within, for example, ERCOT have generally been able to provide for the needs and wants of gas-fired electric generation. Moreover, in Order Number 787, the Federal Energy Regulatory Commission has specifically allowed the sharing of information. The Federal Energy Regulatory Commission is currently considering changes to the timing of the gas day that could better align day-ahead gas scheduling with day-ahead electricity markets. These changes will help with the coordination between gas and electricity markets.
With the large-scale addition of intermittent renewable resources, the variability and uncertainty of net load will correspondingly increase. Increased integration of intermittent renewable resources will imply a more variable net load that must be met by the thermal system.
While wind-forecasting technology used by market participants, wind asset owners, and system operators continues to improve, forecast errors intrinsically increase as predictions are made further into the future. That is, day-ahead forecasts of wind power are relatively more uncertain than in-day forecasts because wind speed forecasts are relatively uncertain within the day-ahead context. Two-day ahead forecasts tend to be worse than day ahead, although forecast error may not worsen much more with further increases in a forecast horizon beyond two days.
There will be a greater need to adjust natural gas consumption during the operational gas day to satisfy the variability and uncertainty of increasing the overall levels of wind and other variable resources, such as photovoltaic resources. As a matter of practice, natural gas markets generally have limited trading intraday and are typically illiquid on weekends and public holidays. A forecast of net load made on Friday for Monday will have rather greater error than a forecast made on Monday for Tuesday. Consequently, natural gas nominations for electricity production on Monday will be relatively less accurate than gas nominations for Tuesday.
Over the last four years, my colleagues and I from the McCombs School of Business, the School of Law, the LBJ School of Public Affairs, and the Cockrell School of Engineering at The University of Texas have convened an annual conference on the electricity industry. At our recent Austin Electricity Conference (http://www.mccombs.utexas.edu/Centers/EMIC/2014-Electricity-Conference), I chaired a panel session that discussed some of these challenges at the gas-electricity nexus. Gas has been an important fuel for electricity in Texas for decades. Other regions of the United States, particularly New England, and other countries have only relatively recently increased the use of natural gas as a fuel for generators, but this has already presented some problems. In New England, for example, the combination of high winter requirements for natural gas for space heating and the relatively limited gas-pipeline infrastructure have generated problems with coordinating the regional gas and electricity markets. ISO New England, despite its ostensible focus on wholesale electric power markets and reliability, has needed to develop in-house expertise in gas supply, delivery, and availability.
As natural gas becomes even more heavily utilized for power generation, the regional gas and electricity markets will become even more tightly coupled. With a rising reliance on gas to balance increasing net load variability and uncertainty, gas demand will become even more variable. Among the various challenges at the gas-electricity nexus, dealing with the need for even more variable natural gas fuel is a problem that seems to be technically solvable. Natural gas storage and other balancing options could allow for solutions that are necessitated by the electricity industry, where supply and demand must be continuously balanced. The natural gas industry needs to adapt to the needs and wants of the electric power industry, which is growing and will soon be the largest consumer of gas. The solutions that are necessary for the gas industry are likely to be relatively simple because the natural gas system has greater storage options and looser requirements on the balancing of gas supply and demand than is required by the electric power system.
The timing of electricity and gas markets will likely need to be better synchronized, as has been widely recognized by the Federal Energy Regulatory Commission and others. Changes in timing have been implemented within some areas. To fully utilize the operational flexibility of natural-gas-fired generation, it will also likely become necessary for there to be more trading opportunities for natural gas within the intraday and day-ahead gas trading markets.
In other words, the natural gas trading industry will need to make changes from their current ìbanker hours.î Natural gas traders may not appreciate this change, but in my view, the increasing needs of this new burgeoning customer, the electricity industry, will soon necessitate a liquid seven-day-a-week gas trading marketplace. I look forward to the natural gas industry making this change as regions such as ERCOT move to even higher levels of variable renewable resource integration.