Aspen Environmental Group
This report—Implications of Greater Reliance on Natural Gas for Electricity Generation—examines theimpacts on natural gas and deliveries to electric utilities should rules limiting utility emissions of carbon or other pollutants result in a shift away from coal towards using more natural gas to generate electricity. It was commissioned by the American Public Power Association (APPA), with financial support from the Utility Air Regulatory Group (UARG) and other electric utilities.
The report begins with a review of the natural gas industry for those who are less familiar with it. It then covers demand, supply, transmission and storage infrastructure, and operational changes that will need to be made by units switching from coal to gas. This report also examines the economics of switches from coal to gas. An understanding of these issues is needed if the electricity industry should need substantially more gas than several studies have suggested. If substantially more gas is needed, then a number of changes will need to be made by both the gas and electricity industries: changes such as massive infrastructure additions, changes to nominating and balancing services, changes to curtailment rules, and changes to subscription levels on interstate pipelines, for starters. The ultimate purpose of the study is to identify those implications so that policy makers can take them into account in deciding what regulations to adopt, and utilities can take them into account in making selections about what resources to use in providing electricity to their customers.
Demand for natural gas now is approximately 23 Trillion Cubic Feet (Tcf) per year in a market split roughly equally between serving the residential and small commercial, industrial, and electric generation sectors. Current demand is only slightly higher than the industry’s prior peak of 22 Tcf in 1972. During that time industrial demand fell off, to be replaced by demand by electric generators. Several studies have looked at what future natural gas demand might be if carbon emissions were regulated. Their answers range considerably, depending on what the studies’ authors assumed about the availability and cost of other generating resources. None of these studies appears to have looked at the full range of regulations that might affect electric generators and might lead to larger numbers of units to be converted from coal-burning to gas-burning. If all existing coal fired generation were to switch to gas today, overall natural gas demand would total 36 Tcf per year, or half again as much as today. Two-thirds of the natural gas produced in the U.S. would serve electric power plants, compared to just under one-third today.
Natural Gas Supply
This report largely takes as a given the expansion of natural gas production arising from shale-based supply and the idea that the industry could provide enough natural gas supply. Yet there remain issues and uncertainty that could affect this supply, as well as its price. Expanding production of shale-deposited gas is attracting environmental concern and in some cases local opposition to gas drilling due to its use of a technique known as hydraulic fracturing. Fracturing injects large amounts of water and chemicals into a well to crack open rock formations and then hold the cracks open so that natural gas can flow up the well. EPA and others are studying the potential adverse impacts of hydraulic fracturing. Even if fracturing continues, serving a much larger market will require even more drilling that is already at record levels. The implied supply curve reflecting the cost of new reserve additions developed herein suggests natural gas prices in the range of $10 per MMBtu to replace the reserves consumed last year. The Energy Information Administration’s AEO 2010 projects a gas price in 2036 of $8 per MMBtu with production not much higher than in 2000; a study for the Interstate Natural Gas Association of America includes a Base Case that projects $6.96 per MMBtu ($ 2008) with production in 2030 of roughly 27 Tcf.In other words, these studies show relatively high natural gas prices at demand levels generally more modest than reviewed herein. With these observations in mind, it seems unwise to expect to serve demand levels that are potentially very much higher than today without sending prices to much higher levels.
To deliver the 60 or so Bcf we use each day from the supply basins where gas is produced to theend-users who will burn it, we use 300,000 miles of natural gas transmission pipelines and associated facilities that provide 130 Bcf per day interregional transfer capability. Nearly half the capacity we have today was built AFTER the industry achieved its previous peak demand of 22+ Tcf in 1972. The new capacity was needed in part to increase flexibility and to serve shifting regional markets, but primarily it was needed because old supply areas depleted and new ones were developed in other regions. Estimates of new pipeline capacity required range from $106 Billion to $163 Billion in one industry study. This study escalates those estimates to $348 Billion should all coal-fired generation need to be replaced with natural gas-fired generation. In looking at existing capacity, 21 states would find the interstate pipeline capacity coming into their state insufficient to serve existing demand plus the demand that would result from converting existing coal-fired generation to gas. These kinds of infrastructure investments are typically financed and recovered in rates over an extended period of time and are expected to continue being used and producing revenue for the owners for years after that. The magnitude of the investment that would be needed (as described in this report) seems inconsistent with the oft-touted idea of natural gas as a temporary “bridge” fuel.
For the electricity industry to broadly switch its coal-fired units to natural gas, it will also need more gas storage capability. Geology limits opportunities to build storage where the market would prefer it. Because of that, the current 400 or so storage facilities are not distributed evenly across the country and many of those facilities are single season reservoirs—rather than higher deliverability salt cavern-based facilities. Areas without much storage include: Nevada, Idaho and Arizona, the Central Plains states, Missouri and virtually the entire East Coast (except far upstream in western New York, western Pennsylvania and West Virginia). Pipelines that have little access to storage include: Florida Gas Transmission, Kern River Gas Transmission, Southern Natural, Transco, Iroquois, Maritimes & Northeast, Alliance, Gas Transmission Northwest, Northern Border, Trailblazer, Transwestern, El Paso Natural Gas, and Williston Basin Pipeline. Scaling storage up to meet double the current electric generation (EG) gas burn implies a need to add 1.4 Tcf of storage. Adding this amount at the average $9 Billion per Tcf derived from a study done for the Interstate Natural Gas Association of America (INGAA) would thus cost close to $12.5 Billion.
The natural gas industry operates using a lot of conventions developed to serve primarily residential, commercial and industrial customers. For example, natural gas is scheduled, or “nominated,” many hours before electric dispatch decisions are made. Tariff provisions that require transporters to match nominations to their usage (i.e., keep their deliveries into a pipeline in “balance” with the amount of gas they actually use) are not customized to provide the additional flexibility electric generators need. Canada’s Province of Ontario helped electricity generators and the gas pipelines develop innovative ways of addressing these issues. Such innovations need to be considered in the U.S. if we are to burn much more gas for electricity generation. Also to be considered is the issue of curtailment. Curtailment halts delivery of natural gas: large customers like electricity generators are typically looked to by local gas distributors’ gas control operations as the first to curtail should supply or pipeline capacity run short. Those that are located along pipelines where capacity is tight often have back-up fuel capability, usually diesel fuel or residual fuel oil that they plan to be able to burn for only a few days. Most generators, however, do not have alternate fuel capability. Hurricanes present another consideration. Even small storms cause crews to be evacuated from offshore drilling and production platforms. Traders bid up prices anticipating damage. Massive storms can cause significant damage to natural gas production infrastructure in the Gulf. For example, as a result of Hurricanes Katrina and Rita in 2005, 80% of U.S. offshore production (which is approximately10% of U.S. total production) remained shut-in for a couple of weeks after Katrina, and again after Rita. Two key studies, including one by Sandia National Laboratories’ National Infrastructure Simulation and Analysis Center, state that the disruption from the storms was not to consumer deliveries, but was absorbed by a reduction in deliveries to gas storage. Those studies, however, do not assess how that impact could be different if coal-fired generation switched to natural gas. It also turns out that winter 2005-2006 was extraordinarily mild; had a normal cold or colder-than-normal winter occurred, gas consumers in the Midwest, MidAtlantic and Northeast might have experienced winter month natural gas curtailments. Finally, many electric utilities today burn little or no natural gas to generate electricity and don’t have trained staff on hand to address these matters. They will need to obtain trained staff or purchase external expertise to manage natural gas procurement, plan their interstate pipeline capacity commitments, and much more closely follow natural gas market developments. They will need staff to “carry the pager” to manage daily nominations and imbalances. They will need to deal with price volatility and risk management on a scale that most have never done before.
What Retrofitting Coal Plants to Burn Natural Gas Means
The electricity industry can theoretically switch to natural gas either by retrofitting existing coal-firedunits to burn natural gas or by closing the coal plants and building new gas-fired plants. Aspen’s research uncovers no instances of coal plant retrofits to natural gas and, in fact, virtually all of the public references to conversion of coal to natural gas or repowering turn out instead to be replacements. The reason is economics. Even the U.S. Government Accountability Office (GAO), when it looked at this issue switching the Capitol Building power plant to natural gas, noted that not only was switching all U.S. coal-fired generation infeasible due the gas supply and infrastructure required, but that it would be more cost-effective to construct new gas-fired units than to retrofit existing coal-fired units to burn natural gas. Combined-cycle gas-fired generation costs roughly $1 million per MW, installed. Replacing 335,000 MW of coal-fired generation thus should cost in the range of $335 billion. Additionally, even if gas-fired units are built to replace existing coal-fired units, many utilities likely still have outstanding debt service on the coal plants that must be covered. Most plants are financed over a 20- or even 30-year period and roughly 30% of the existing fleet is 30 years old or less. The need to complete paying off this debt and the impact on utility cash flow needs to be recognized as part of the cost of replacement.