Natural Gas in the U.S. Electric Power Sector

Introduction

Figure 1: Electricity Generation Additions by Fuel Type 2010 – 2035 (GW)

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Source: Energy Information Agency, U.S. Department of Energy, 2011 [11]

With the increasing likelihood of a carbon-constrained future, cleaner than coal emissions and forecasts of sustained low prices, natural gas has become the fuel of choice for electricity generation by utilities [12] in the United States.[1] In 2012, the electric power industry [13] planned to bring 23.5 GW of new capacity on line with 37 percent being natural gas-fired (20 percent wind, 18 percent coal, 12 percent solar, 5 percent nuclear, and 8 percent other sources, including hydro, geothermal and biomass). With growing electricity demand and the planned retirement of 39 GW of existing capacity, 223 GW of new generating capacity [13] (including end-use combined heat and power) will be needed between 2010 and 2035. Natural-gas-fired plants account for 60 percent of capacity additions between 2010 and 2035 in the EIA Annual Energy Outlook 2011 [13] Reference case, compared with 25 percent for renewables, 11 percent for coal-fired plants, and 3 percent for nuclear. Note that Federal tax incentives and state energy programs contribute to renewables competitiveness [14] in the 2010 – 2015 time period. For example, with the Production Tax Credit [11] in place until December 2012, wind generation capacity increases more than 18 GW from 2010 – 2015, and with the Investment Tax Credit in place until December 2016, utility and end-use solar capacity additions are forecast to increase by 6.3 GW (7.5 GW through 2016).
 

Natural Gas as a Fuel for Electric Power

Natural gas can provide baseload, intermediate and peaking electric power. It is a reliable source [15] of power that is capable of supplying firm back-up to intermittent wind and solar. Additionally, natural gas power plants can be constructed relatively quickly, in as little as 20 months.[2] Compared to other forms of electric generation natural gas plants have a small footprint from a land use perspective. However, even though natural gas combustion emits fewer GHGs than coal or oil, it still emits a significant amount of CO₂. It is also important to stress that natural gas-fired electrical plants must be sited near existing natural gas pipelines; otherwise the cost of building this infrastructure must be taken into account.
 

Greenhouse Gas Emissions

The electricity sector contributes about 40 percent [16] of all U.S. carbon dioxide emissions. All other things being equal, a megawatt-hour of natural gas-fired generation contributes around half the amount of CO₂ emissions from coal-fired generation and about 68 percent of the amount of CO₂ emissions from oil-fired generation. Natural gas-fired generation CO₂ emissions levels are still significant, especially when compared to the near-zero emissions of nuclear, hydro, wind, geothermal, and solar power.

Centralized Power Generation

Central power stations create large quantities of electricity, which are then transported to end-users via electrical transmission and distribution lines. There are three categories of central power station technologies in which natural gas is a fuel that can be used to generate the electricity. In the order of their historical development, they are: steam turbines, combustion turbines (CT) and combined cycle (CC) power plants. Each plant type has an associated average thermal efficiency. Thermal efficiency measures how well a technology converts the fuel input energy (heat) into electrical energy (power). A higher thermal efficiency, other things being equal, indicates that less fuel is required to generate the same amount of electricity, resulting in fewer emissions. Steam turbines have the lowest efficiency at around 33 - 35 percent. Combustion turbines are around 35 - 40 percent efficient and combined cycle plants have thermal efficiencies in the range of 50 - 60 percent. For more information about these three technologies see Appendix A.
 

Distributed Generation (DG)

With distributed generation systems (also referred to as self-generation), as contrasted to central power station generation described above, smaller quantities of electricity are generated at or near the location where it will be consumed, obviating the need for long electrical transmission lines. The potential benefits include [17]: increased electric system reliability, reduction of peak power requirements, and reduction in vulnerability to terrorism. However, from a greenhouse gas (GHG) perspective, the primary advantage of distributed generation is that there are fewer losses in the transmission [17] of the electric power, both in the bulk transmission system and in the local electrical distribution networks. Lowering line losses means less electricity generation (less fuel and fewer emissions) is required to serve the same electrical demand.

In the bulk transmission system [18] (the backbone of the central power station system), line losses depend primarily on the line voltage, line load, weather, altitude and the distance travelled; the higher the line voltage the fewer losses that a line will experience. For example, a 765kV line, the highest voltage currently used in the bulk transmission system [18], electrical losses are on the order of 0.6 to 1.1 percent for a 1000 MW line load travelling 100 miles in normal weather. A 345kV line [18] under the same conditions would see a loss on the order of 4.2 percent. Since most local distribution companies [19] operate below 35kV, higher losses can be expected in the local distribution network.

Examples of DG that would utilize natural gas include microturbines (CT or CC) located on-site for commercial and residential application, and combined heat and power (CHP) for industry.  CHP also has additional efficiency benefits beyond those from DG (see companion paper - Natural Gas in the Industrial Sector [3]). Higher capital costs are believed to prevent investment in DG technologies and the State of California [20], among others, provides incentives for self-generation.
 

Future Technology – Supply Side Efficiency

The Electric Power Research Institute [21] (EPRI) asserts that it is technologically and economically feasible to improve the thermal efficiencies of steam turbine technology by 3 percent, increase combustion turbines to 45 percent efficient, and construct combined cycle plants with 70 percent efficiency by 2030. Higher thermal efficiencies translate into less fuel required to generate the same amount of electricity. EPRI’s 2009 analysis [21] estimates a potential CO₂ emissions reduction in 2030 of 3.7 percent as a result of increasing the efficiency of new and existing fossil-fueled generation.
 

Policy in Play

Arguably, the most significant policy decisions affecting the U.S. electric power sector today are the Cross State Air Pollution Rule (CSAPR), National Emissions Standards for Hazardous Air Pollutants (NESHAP), and proposed New Source Performance Standards (NSPS) issued by the U.S. Environmental Protection Agency (EPA). The installation of pollution control retrofits will be essential to comply with CSAPR and NESHAP, affecting electric generating units, and coal-fired units in particular.[3] PJM, operator of the world’s largest wholesale electricity market in the Eastern U.S., predicts that approximately 14 GW of coal-fired generation out of an installed capacity of 78.6 GW of coal-fired generation could be retired by 2015 largely due to EPA rules.[4] Reserve margins, the spare capacity that electricity system or market operators are required to maintain above projected peak loads to ensure system reliability appear sufficient in the short run. However, new, reliable baseload generation will be required in the next ten to twenty years to fill the gap.

Additionally, in late March 2012, the EPA proposed CO₂ pollution standards [22] for the new electric power plants as part of its NSPS program. Under the proposed standard [22] (1,000 pounds of CO₂ per MWh), all new power plants would need to match the CO₂ emissions performance currently achieved by highly efficient natural gas combined cycle (NGCC) power plants. New coal-fired power plants could meet the standard [22] by capturing and permanently sequestering their GHG emissions using carbon capture and storage (CCS) technologies. If adopted, this standard would favor new natural gas-fired generation in the future.

In the past few years, there has been interest in a Federal level Renewable Portfolio Standard (RPS). Most recently, there has been some interest in a broader Federal Clean Energy Standard (CES). A CES is a policy requiring that a certain portion of electricity sold by an electric utility come from “clean energy” sources [23]. Whereas an RPS typically credits only 100 percent renewable generation like wind turbines, solar, geothermal or new hydro, a CES creates a mechanism to credit “cleaner” electricity generation, that is, generation that creates less CO₂. Therefore, new and incremental (upgrades and improvements to) natural gas-fired generation, along with natural gas with carbon capture and storage (CCS), among other cleaner forms of electricity production [23] would be eligible to receive clean energy credits.
 

Natural Gas in the Electricity Market

In 1978, in response to supply shortages (the result of government price controls), Congress enacted the Power Plant and Industrial Fuel Use Act [24] (FUA). The law prohibited the use of oil and natural gas in new industrial boilers and new electric power plants. The goal was to preserve "scarce" supplies [25] for residential customers. During the early 1980s, the demand for natural gas declined substantially [24], which contributed to a significant oversupply of gas for much of the decade. Falling natural gas demand and prices finally spurred the repeal [24] in 1987 of sections of the FUA that restricted the use of natural gas by industrial users and electric utilities. Low natural gas prices in the 1990s stimulated the rapid construction [26] of gas-fired power plants. Since 1990, natural gas has been gaining market share [27] with electricity generation from this source increasing from around 11 percent to 23 percent of the total net generation in 2010, as illustrated in Figure 2.

Figure 2: Electricity Net Generation: Electric Power Sector (GWh)

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Source: Energy Information Agency, U.S. Department of Energy, 2011 [27]

As a result of increased natural gas-fired electricity generation [27] displacing fuel oil and coal-fired generation, total GHG emissions from the electricity sector have decreased since 2000, as shown in Figure 3, while net electricity generation has increased around 9 percent over the same period.

Figure 3: Emissions: Electric Power Sector (MMT CO2)

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Source: Energy Information Agency, U.S. Department of Energy, 2011 [27]

According to the latest Energy Information Administration (EIA) Annual Energy Outlook [30] (AEO), natural gas-fired generation is expected to be just over 25 percent of the total generation mix in 2020, rising to 27 percent in 2035.

Fuel diversity [31] is an important consideration for utilities looking to reduce their reliance on any particular energy source. The trend away from coal toward greater reliance on natural gas creates a potential fuel diversity risk, especially considering the volatile price history of natural gas. Coal will continue to be a significant source of electricity in some regions and for some utilities, but other utilities look increasingly likely to be getting nearly all of their baseload generation [12] from only two sources: natural gas and nuclear power.

Figure 4: Estimated Levelized [27] Cost of New Generation Resource, 2016

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Source: Energy Information Agency, U.S. Department of Energy, 2011 [27]

Levelized cost (Figure 4) represents [33] the present value of the total cost of building and operating a generating plant over an assumed financial life and duty cycle, converted to equal annual payments and expressed in terms of real dollars to remove the impact of inflation. It reflects overnight capital cost, fuel cost, fixed and variable O&M cost, financing costs, and an assumed utilization rate for each plant type. The availability of various incentives including state or federal tax credits [33] can also impact the calculation of levelized cost. The values shown [33] in the figure below do not incorporate any such incentives. Natural gas-fired combined-cycle generation technologies are projected to be the least expensive options in the coming years. Utilities looking at their bottom lines and public utility commissions looking for low-cost investment decisions will favor the construction of natural gas-fired technologies, leading to a greater reliance on natural gas in the coming years.

Natural Gas with Carbon Capture and Storage

In a carbon-constrained future, and with natural gas potentially playing a much greater role in the future of the total generation mix, it makes sense to consider a natural gas plant with carbon capture and storage (CCS) capability. CCS projects have already been initiated and several projects are planned in the next several years to demonstrate the feasibility of the CCS technology [34]. To date, these projects [34] have been undertaken almost exclusively in conjunction with coal-fired power plants or industrial sources. However, one international project in Norway, set to begin in 2012, endeavors to capture CO₂ from a natural gas combined heat and power (CHP) plant (similar to a combined cycle plant) and sequester [34] the CO₂ in an underground saline formation.

In addition to sequestering CO₂ in saline formations, CO₂ is currently being injected into oil wells as part of tertiary, or enhanced, oil production (CO₂-EOR [35]). This storage option has the added benefit of providing an economic incentive, that is, compensation from the oil-field operator to the captured CO₂ provider.  In 2011, the National Enhanced Oil Recovery Initiative (NEORI) was formed to help realize CO₂-EOR’s full potential [35] as a national energy security, economic, and environmental strategy. In addition, NEORI [35] suggests federal- and state-level action to support CO₂-EOR.