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- Electric utilities are showing an overwhelming preference for building new natural gas power plants.
- Distributed or locally generated electricity has lower greenhouse gas (GHG) emissions relative to centralized generation because of avoided transmission losses.
- Significant improvements in power plant thermal efficiencies are feasible by 2030.
- Environmental rules are driving coal plant retirement, providing an opportunity for other forms of baseload generation.
|Figure 1: Electricity Generation Additions by Fuel Type 2010 – 2035 (GW)|
|Source: Energy Information Agency, U.S. Department of Energy, 2011|
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 in the United States. In 2012, the electric power industry 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 (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 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 in the 2010 – 2015 time period. For example, with the Production Tax Credit 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 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. 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 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.
|Table 1: Average Fossil Fuel Power Plant Emission Rates (lbs/MWh)|
|Source: U.S. Environmental Protection Agency, 2000|
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: 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 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 (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, 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 under the same conditions would see a loss on the order of 4.2 percent. Since most local distribution companies 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). Higher capital costs are believed to prevent investment in DG technologies and the State of California, among others, provides incentives for self-generation.
Future Technology – Supply Side Efficiency
The Electric Power Research Institute (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 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. 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. 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 for the new electric power plants as part of its NSPS program. Under the proposed standard (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 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. 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 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 (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 for residential customers. During the early 1980s, the demand for natural gas declined substantially, which contributed to a significant oversupply of gas for much of the decade. Falling natural gas demand and prices finally spurred the repeal 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 of gas-fired power plants. Since 1990, natural gas has been gaining market share 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)|
|Source: Energy Information Agency, U.S. Department of Energy, 2011|
As a result of increased natural gas-fired electricity generation 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)|
|Source: Energy Information Agency, U.S. Department of Energy, 2011|
According to the latest Energy Information Administration (EIA) Annual Energy Outlook (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 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 from only two sources: natural gas and nuclear power.
|Figure 4: Estimated Levelized Cost of New Generation Resource, 2016|
|Source: Energy Information Agency, U.S. Department of Energy, 2011|
Levelized cost (Figure 4) represents 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 can also impact the calculation of levelized cost. The values shown 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. To date, these projects 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 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). 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 as a national energy security, economic, and environmental strategy. In addition, NEORI suggests federal- and state-level action to support CO2-EOR.
3. PJM Interconnection. “Coal Capacity at Risk for Retirement in PJM: Potential Impacts of the Finalized EPA Cross State Air Pollution Rule and Proposed National Emissions Standards for Hazardous Air Pollutants,” August 26, 2011.
by Michael E. Weber, The University of Texas at Austin
- Within one to two decades, natural gas might surpass petroleum as the dominant energy source in the United States.
- A period of price choppiness may occur as U.S. natural gas prices settle to a new equilibrium.
- As a marginal power producer, high natural gas prices trigger high electricity prices that make it easier for renewable energy sources to compete.
- Low natural gas prices encourage the replacement of coal in the power sector.
- The relationship between natural gas and wind is nuanced, as they mitigate each other’s worst problems—winds’ variability and natural gas’ price volatility.
- Renewable forms of natural gas, biogas or biomethane, have a potential domestic supply of over 1 quadrillion British thermal units (Btus) annually.
Energy transitions are a way of life. And, it seems that the United States is undergoing another one of those transitions as it seeks lower-carbon, more affordable, domestically-sourced fuels to meet a variety of market and policy objectives. The brief history of energy consumption in the U.S. from 1800 to 2010 is depicted in Figure 1, revealing that we have already experienced several energy transitions. Wood as our dominant fuel in the first half of the 19th century was surpassed by coal starting in 1885.
Coal as our dominant fuel was surpassed by petroleum in 1950. Whether another such a transition is underway is yet to be seen. But, if recent trends continue, then it seems likely that another transition will occur in the coming one to two decades as natural gas overtakes petroleum to be the most popular primary energy source in the U.S. Such a transition will be enabled (or inhibited) by a mixed set of competing price pressures and a complicated relationship with renewables that will trigger an array of market and cultural responses. This article seeks to layout some of the key underlying trends while also identifying some of these different axes of price tensions (or price dichotomies).
|Figure 1: Total U.S. Energy Consumption, 1800 to 2010|
Note: Wood, which was the dominant fuel in the U.S. for the first half of the 19th century, was surpassed by coal starting in 1885. Coal as the dominant fuel was surpassed by petroleum in 1950. Within one to two decades, natural gas might surpass petroleum as the dominant energy provider.
Source: Energy Information Agency 2010
Natural Gas Could Become Dominant in the U.S. Within One to Two Decades
While petroleum still reigns supreme today, within one to two decades, natural gas might surpass it as the dominant energy provider. In fact, recent trends suggest that another transition is already underway. In particular, while petroleum and coal consumption have dropped steadily since 2006, natural gas consumption has increased.
For a century, oil and natural gas consumption trends have tracked each other quite closely. Figure 2 shows normalized U.S. oil and gas consumption from 1920 to 2010 (consumption in 1960 is set to a value of 1.0). These normalized consumption curves illustrate how closely oil and gas have tracked each other up until 2002, at which time their paths diverged: natural gas consumption declined from 2002 to 2006, while petroleum use grew over that time period. Then, they went the other direction: natural gas consumption grew and oil production dropped. That trend continues today, as natural gas pursues an upward path, whereas petroleum is continuing a downward trend.
The growing consumption of natural gas is driven by a few key factors:
- It has flexible use across many sectors, including direct use on-site for heating and power; use at power plants; use in industry; and growing use in transportation.
- It has lower emissions (of pollutants and greenhouse gases) per unit of energy than coal and petroleum.
- It is less water-intensive than coal, petroleum, nuclear and biofuels.
- Domestic production meets almost all of the annual U.S. consumption.
|Figure 2: U.S. Oil and Gas Consumption from 1920 to 2010|
Note: U.S. oil and gas consumption from 1920 to present day (normalized to a value of 1 in 1960) shows how oil and gas have tracked each other relatively closely until 2002, after which their paths diverge. Since 2006, natural gas consumption has increased while petroleum consumption has decreased.
Source: Energy Information Agency 2010
By contrast, the trends for petroleum and coal are moving downwards. Petroleum use is expected to drop as a consequence of price pressures and policy mandates. The price pressures are triggered primarily by the split in energy prices between natural gas and petroleum (discussed in detail below). The mandates include biofuels production targets (which increase the production of an alternative to petroleum) and fuel economy standards (which decrease the demand for liquid transportation fuels). At the same time, coal use is also likely to drop because of projections by the EIA for price doubling over the next 20 years and environmental standards that are expected to tighten the tolerance for emissions of heavy metals, sulfur oxides, nitrogen oxides, particulate matter and CO2.
Petroleum use might decline 0.9 percent annually from the biofuels mandates themselves. Taking that value as the baseline, and matching it with an annual growth of 0.9 percent in natural gas consumption (which is a conservative estimation based on trends from the last 6 years, plus recent projections for increased use of natural gas by the power and industrial sectors), indicates that natural gas will surpass petroleum in 2032, two decades from now. A steeper projection of 1.8 percent annual declines in petroleum matched with 1.8 percent annual increase in natural gas consumption sees a faster transition, with natural gas surpassing petroleum in less than a decade.
While such diverging rates might seem aggressive, they are a better approximation of the trends over the last six years than the respective 0.9 percent values. An annual decline in petroleum of 1.8 percent is plausible through a combination of biofuels mandates (0.9 percent annual decline), higher fuel economy standards (0.15 percent annual decline), and price competition that causes fuel-switching from petroleum to natural gas in the transportation (heavy-duty, primarily) and industrial sectors (0.75 percent annual decline). Natural gas growth rates of 1.8 percent annually can be achieved by natural gas displacing 25 percent of diesel use (for on-site power generation and transportation) and natural gas combined cycle power plants displacing 25 percent of 1970s–1980s vintage coal-fired power plants by 2022. While this scenario is bullish for natural gas, it is not implausible, especially for the power sector, whose power plants face retirement and stricter air quality standards. Coupling those projections with reductions in per capita energy use of 10 percent (< 1 percent annually) over that same span imply that total energy use would stay the same.
These positive trends for natural gas are not to say it is problem-free. Environmental challenges exist for water, land and air. Water challenges are related to quality (from risks of contamination) and quantity (from competition with local uses and depletion of reservoirs). Land risks include surface disturbance from production activity and induced seismicity from wastewater reinjection. Air risks are primarily derived from leaks on-site, leaks through the distribution system, and flaring at the point of production. Furthermore, while natural gas prices have been relatively affordable and stable in the last few years, natural gas prices have traditionally been very volatile. However, if those economic and environmental risks are managed properly, then these positive trends are entirely possible.
There are Six Price Dichotomies with Natural Gas
In light of the looming transition to natural gas as the dominant fuel in the U.S., it is worth contemplating the complicated pricing relationship that natural gas in the U.S. has with other fuels, market factors, and regions. It turns out that there are several relevant price dichotomies to keep in mind:
- Natural Gas vs. Petroleum Prices,
- U.S. vs. Global Prices,
- Prices for Abundant Supply vs. Prices for Abundant Demand,
- Low Prices for the Environment vs. High Prices for the Environment,
- Stable vs. Volatile Prices, and
- Long-Term vs. Near-Term Prices.
The tensions along these price axes will likely play an important role in driving the future of natural gas in the U.S. and globally.
|Figure 3: U.S. Oil and Gas Consumption and Projections|
Note: Natural gas might pass petroleum as the primary fuel source in the U.S. within one to two decades, depending on the annual rate of decreases in petroleum consumption and increases in natural gas consumption. Historical values plotted are from EIA data.
Source: Energy Information Agency 2010
Decoupling of Natural Gas and Petroleum Prices
One of the most important recent trends has been the decoupling of natural gas and petroleum prices. Figure 4 shows the U.S. prices for natural gas and petroleum (wellhead, and WTI Cushing, respectively) from 1988 to 2012. While natural gas and petroleum prices have roughly tracked each other in the U.S. for decades, their trends started to diverge in 2009 as global oil supplies remained tight, yet shale gas production increased. This recent divergence has been particularly stark, as it’s driven by the simultaneous downward swing in natural gas prices and upward swing in petroleum prices. For many years, the ratio in prices (per million BTU, or MMBTU) between petroleum and natural gas oscillated nominally in the range of 1–2, averaging 1.6 for 2000–2008. However, after the divergence began in 2009, this spread became much larger, averaging 4.2 for 2011 and, remarkably, achieving ratios greater than 9 spanning much of the first quarter of 2012 (for example, natural gas costs approximately $2/MMBTU today, whereas petroleum costs $18/MMBTU).
This spread is relatively unprecedented and, if sustained, opens up new market opportunities for gas to compete with oil through fuel-switching by end-users and the construction of large-scale fuel processing facilities. For the former, these price spreads might inspire institutions with large fleets of diesel trucks (such as municipalities, shipping companies, etc.) to consider investing in retrofitting existing trucks or ordering new trucks that operate on natural gas instead of diesel to take advantage of the savings in fuel costs. For the latter, energy companies might consider investing in multi-billion dollar gas-to-liquids (GTL) facilities to convert the relatively inexpensive gas into relatively valuable liquids.
|Figure 4: U.S. Oil and Gas Prices 1988 to 2012|
While natural gas and petroleum prices have roughly tracked each other in the U.S. for decades, their price trends started to diverge in 2009.
Decoupling of U.S. and Global Prices
Another important trend has been the decoupling of U.S. and global prices for natural gas. Figure 5 shows the U.S. prices for natural gas (at Henry Hub) compared with EU and Japanese prices from 1992 to 2012. In a similar fashion as the discussion in Section 3.1, while natural gas prices in the U.S. and globally (in particular, the EU and Japan) have tracked each other for decades, their price trends started to diverge in 2009 because of the growth in domestic gas production. In fact, from 2003–2005, U.S. natural gas prices were higher than in the EU and Japan because of declining domestic production and limited capacity for importing liquefied natural gas (LNG). At that time, and for the preceding years, the U.S. prices were tightly coupled to global markets through its LNG imports setting the marginal price of gas.
Consequently, billions of dollars of investments were made to increase LNG import capacity in the U.S. That new import capacity came online concurrently with higher domestic production, in what can only be described as horribly ironic timing: because domestic production grew so quickly, those new imports were no longer necessary, and much of that importing capacity remains idle today. In fact, once production increased in 2009, the U.S. was then limited by its capacity to export LNG (which is in contrast to the situation just a few years prior, during which the U.S. was limited by its capacity to import gas), so gas prices plummeted despite growing global demand. Thus, while the U.S. was tightly coupled to global gas markets for well over a decade, it has been decoupled for the last several years. At the same time, the EU and Japan are tightly coupled to the world gas markets, (with the EU served by LNG and pipelines from the Former Soviet Union, and Japan served by LNG). How long these prices remain decoupled will depend on U.S. production of natural gas, U.S. demand for natural gas, and the time it takes for these isolated markets to connect again. In fact, LNG terminal operators are now investing billions of dollars to turn their terminals around so that they can buy cheap natural gas in the U.S. that they can sell at higher prices to the EU and Japan. Once those terminals are turned around, these geographically-divergent market prices should come back into convergence.
|Figure 5: Natural Gas Prices in Japan, the E.U. and U.S., 1992 to 2012|
Note: While natural gas prices in the U.S. and globally (EU and Japan) have tracked each other for decades, their price trends started to diverge in 2009.
Sources: BP 2010, EIA 2012—Henry Hub Gulf Coast Natural Gas Spot Price and Price of Liquefied U.S. Natural Gas Exports to Japan, and Ycharts 2012
Prices for Abundant Supply vs. Prices for Abundant Demand
Another axis to consider for natural gas prices is the tension between the price at which we have abundant supply, and the price at which we have abundant demand. These levels have changed over the years as technology improves and the prices of competing fuels have shifted, but it seems clear that there is still a difference between the prices that consumers wish to pay and producers wish to collect. In particular, above a certain price (say, somewhere in the range of $4–8/MMBTU, though there is no single threshold that everyone agrees upon), the U.S. would be awash in natural gas. Higher prices make it possible to economically produce many marginal plays, yielding dramatic increases in total production. However, at those higher prices, the demand for gas is relatively lower because cheaper alternatives (nominally coal, wind, nuclear and petroleum) might be more attractive options. At the same time, as recent history has demonstrated, below a certain price (say, somewhere in the range of $1–3/MMBTU), there is significant demand for natural gas in the power sector (as an alternative to coal) and the industrial sector (because of revitalized chemical manufacturing, which depends heavily on natural gas as a feedstock). Furthermore, if prices are expected to remain low, then demand for natural gas would increase in the residential and commercial sectors (as an alternative to electricity for water heating, for example), and in the transportation sector (to take advantage of price spreads with diesel, as noted above).
The irony here is that it’s not clear that the prices at which there will be significant increases in demand will be high enough to justify the higher costs that will be necessary to induce increases in supply, and so there might be a period of choppiness in the market as the prices settle into their equilibrium. Furthermore, as global coal and oil prices increase (because of surging demand from China and other rapidly-growing economies), the thresholds for this equilibrium are likely to change. As oil prices increase, natural gas production will increase at many wells as a byproduct of liquids production, whether the gas was desired or not. Since the liquids are often used to justify the costs of a new well, the marginal cost of the associated gas production can be quite low. Thus, natural gas production might increase even without upward pressure from gas prices, which lowers the price threshold above which there will be abundant supply. At the same time, coal costs are increasing globally, which raises the threshold below which there is abundant demand. Hopefully, these moving thresholds will converge at a stable medium, though it is too early to tell. If the price settles too high, then demand might retract; if it settles too low, the production might shrink, which might trigger an oscillating pattern of price swings.
Low Prices for the Environment vs. High Prices for the Environment
Another axis of price tension for natural gas is whether high prices or low prices are better for achieving environmental goals such as reducing the energy sector’s emissions and water use. In many ways, high natural gas prices have significant environmental advantages because they induce conservation and enable market penetration by relatively expensive renewables. In particular, because it is common for natural gas to be the marginal power producer in the U.S., high natural gas prices trigger high electricity prices. Those higher electricity prices make it easier for renewable energy sources such as wind and solar power to compete in the markets. Thus, high natural gas prices are useful for reducing consumption overall and for spurring growth in novel generation technologies.
However, inexpensive natural gas also has important environmental advantages by displacing coal in the power sector. Notably, by contrast with natural gas prices, which have decreased for several years in a row, prevailing coal prices have increased steadily for over a decade due to higher transportation costs (which are coupled to diesel prices that have increased over that span), depletion of mines, and increased global demand. As coal prices track higher and natural gas prices track lower, natural gas has become a more cost-effective fuel for power generation for many utility companies. Consequently, coal’s share of primary energy consumption for electricity generation has dropped from 53 percent in 2003 to less than 46 percent in 2011 (with further drops in the first quarter of 2012), while the share fulfilled by natural gas grew from 14 percent to 20 percent over the same span. At the same time, there was a slight drop in overall electricity generation due to the economic recession, which means the rise of natural gas came at the expense of coal, rather than in addition to coal. Consequently, for those wishing to achieve the environmental goals of dialing back on power generation from coal, low natural gas prices have a powerful effect.
These attractive market opportunities are offset in some respects by the negative environmental impacts that are occurring from production in the Bakken and Eagle Ford shale plays in North Dakota and Texas. At those locations, significant volumes of gases are flared because the gas is too inexpensive to justify rapid construction of the pricey distribution systems that would be necessary to move the fuel to markets. Consequently, for many operators it ends up being cheaper in many cases to flare the gas rather than to harness and distribute it.
And, thus, the full tension between the “environmental price” of gas is laid out: low prices are good because they displace coal, whereas high prices are good because they bring forward conservation and renewable alternatives. This price axis will be important to watch from a policymaker’s point of view as time moves forward.
Stable vs. Volatile Prices
One of the historical criticisms of natural gas has been its relative volatility, especially as compared with coal and nuclear fuels, which are the other major primary energy sources for the power sector. This volatility is a consequence of large seasonal swings in gas consumption (for example, for space and water heating in the winter) along with the association of gas production with oil, which is also volatile. Thus, large magnitude swings in demand and supply can be occurring simultaneously, but in opposing directions. However, two forces are mitigating this volatility. Firstly, because natural gas prices are decoupling from oil prices (as discussed in Section 3.1), one layer of volatility is reduced. Many gas plays are produced independently of oil production. Consequently, there is a possibility for long-term supply contracts at fixed prices. Secondly, the increased use of natural gas consumption in the power sector, helps to mitigate some of the seasonal swings as the consumption of gas for heating in the winter might be better matched with consumption in the summer for power generation to meeting air conditioning load requirements.
Between more balanced demand throughout the year and long-term pricing, the prospects for better stability look better. At the same time, coal, which has historically enjoyed very stable prices, is starting to see higher volatility because its costs are coupled with the price of diesel for transportation. Thus, ironically, while natural gas is reducing its exposure to oil as a driver for volatility, coal is increasing its exposure.
Long-Term vs. Near-Term Price
While natural gas is enjoying a period of relatively stable and low prices at the time of this writing in 2012, there are several prospects that might put upward pressure on the long-term prices. These key drivers are: 1) increasing demand, and 2) re-coupling with global markets.
As discussed above, there are several key forcing functions for higher demand. Namely, because natural gas is relatively cleaner, less carbon-intensive, and less water-intensive than coal, it might continue its trend of taking away market share from coal in the power sector to meet increasingly stringent environmental standards. While this trend is primarily driven by environmental constraints, its effect will be amplified as long as natural gas prices remain low. While fuel-switching in the power sector will likely have the biggest overall impact on new natural gas demand, the same environmental and economic drivers might also induce fuel-switching in the transportation sector (from diesel to natural gas), and residential and commercial sectors (from fuel oil to natural gas for boilers, and from electric heating to natural gas heating). If cumulative demand increases significantly from these different factors, but supply does not grow in a commensurate fashion, then prices will move upwards.
The other factor is the potential for re-coupling U.S. and global gas markets. While they are mostly empty today, many LNG import terminals are seeking to reverse their orientation, with an expectation that they will be ready for export beginning in 2014. Once they are able to export gas to EU and Japanese markets, then domestic gas producers will have additional markets for their product. If those external markets maintain their much higher prevailing prices (similar to what is illustrated in Figure 5), re-coupling will push prices upwards.
Concluding Comments on Price Dichotomies
Each of these different axes of price tensions reflects a different nuance of the complicated, global natural gas system. In particular, they exemplify the different market, technological and societal forces that will drive—and be driven by—the future of natural gas.
The Complicated Relationship of Natural Gas and Renewables
In addition to the complex pricing landscape described earlier, there is also a complicated relationship between natural gas and renewables in the power sector stemming from two aspects: 1) competition in the dispatch order between natural gas and renewables, and 2) the potential to produce renewable forms of natural gas.
For the most part, the relationship between natural gas and renewables is interpreted as competition in the power sector, by which renewables are seen as a threat to natural gas because they push natural gas-fired power plants off the bid stack. This phenomenon occurs because the power markets take bids on marginal costs, rather than all-in costs. Because the marginal cost of wind is zero, it bids zero (or negative in some cases, reflecting the effect of production tax credits for wind power). Consequently, it is a price-taker in the markets, and displaces the highest bidders, which are the price-setters. Historically, those price-setters are natural gas power plants, and so wind power displaces natural gas. Consequently the relationship between gas and wind is one of rivalry. Natural gas interests audibly complain about this rivalry, with the criticism that policy supports for wind give it an unfair advantage in this competition. Renewable energy supporters counter that gas interests are not required to pay for their pollution (which is a form of indirect subsidy) and have enjoyed government largesse in one form or another for many decades.
Despite the perception that wind and natural gas are vicious competitors in a zero-sum game where the success of one must come at the demise of the other, the relationship is actually more nuanced. In fact, wind and gas benefit from each other because they both mitigate each other’s worst problems. For wind, intermittency is a problem, and for natural gas, price volatility is a problem. It turns out that the ability for natural gas power plants to serve as rapid response firming power is an effective hedge against wind’s intermittency. And, it turns out the fixed fuel price (at zero) of wind farms is an effective edge against natural price volatility. Thus, they are complementary partners in the power markets.
Furthermore, many people seeking a long-term sustainable energy option will often reject natural gas automatically because it is widely considered a fossil fuel that has a finite resource base. While most reserves of natural gas were formed many millions of years ago (and thus comprise a finite fossil resource), it is important to note that there are also renewable forms of natural gas, known as biogas or biomethane. This form of gas is mostly methane with a balance of CO2, and is created from the anaerobic decomposition of organic matter. While renewable natural gas is a small fraction of the overall gas supply, it is not negligible. For example, landfill gas is already an important contributor to local fuel supplies at the local scale. And, recent studies have noted that the total potential supply available from wastewater treatment plants and anaerobic digestion of livestock waste is over 1 quadrillion BTU annually in the United States.
Overall, it is clear that natural gas has an important opportunity to take market share from other primary fuels. In particular, it could displace coal in the power sector, petroleum in the transportation sector, and fuel oil in the commercial and residential sectors. With sustained growth in demand for natural gas, coupled with decreases in demand for coal and petroleum because of environmental and security concerns, natural gas could overtake petroleum to be the most widely used fuel in the United States within one to two decades. Along the path towards that transition, natural gas will experience a variety of price tensions that are manifestations of the different market, technological and societal forces that will drive—and be driven by—the future of natural gas. These tensions are exacerbated by the complicated relationship between natural gas and renewables. How and whether we sort out these tensions and relationships will affect the fate of natural gas and are worthy of further scrutiny.
5. EIA, Henry Hub Gulf Coast Natural Gas Spot Price, Tech. rep., Energy Information Administration, U.S. Department of Energy, Available at: http://tonto.eia.gov/dnav/ng/hist/rngwhhdm.htm (April 6, 2012).
6. EIA, Price of Liquefied U.S. Natural Gas Exports to Japan, Tech. rep., Energy Information Administration, U.S. Department of Energy, Available at: http://www.eia.gov/dnav/ng/hist/n9133ja3m.htm (April 6, 2012).
7. YCharts, European Natural Gas Import Price, Tech. rep., Available at: http://ycharts.com/indicators/europe_natural_gas_price (April 6, 2012).
- The industrial sector directly consumed 27 percent of natural gas in the United States in 2010.
- Newly abundant and low-cost domestic sources provide economic benefits to industry using the fuel for power, heat, and as a feedstock.
- The Energy Information Agency projects total natural gas consumption for industrial heat and power to rise by 6.25 percent between 2012 and 2021 before declining to lower but steady levels through 2035, and it projects natural gas feedstock use to rise by 25 percent between 2012 and 2035.
- Boiler upgrades and replacements can offer measurable reductions in greenhouse gas emissions through efficiency improvements as well as displacing coal with gas.
- Combined heat and power systems offer the potential to efficiently use natural gas while reducing greenhouse gas emissions.
- Many industrial activities are energy- and emissions-intensive, but some uses of natural gas as a feedstock emit very few greenhouse gases.
|Figure 1: Natural Gas Use in the Industrial Sector (Industry Overall)|
|Source: EIA Manufacturing Energy Consumption Survey (MECS), 2010|
Overall, the largest direct use of energy by the industrial sector is for process heating, which is the production of heat directly from fuel sources, electricity, or steam to heat raw material inputs during manufacturing. In 2010 process heating using all fuel sources produced 315.4 million metric tons of C02e, which was 40 percent of the total emissions for the industrial sector. Natural gas is the dominant fuel used to generate heat, and process heating accounts for 42 percent of the natural gas use in the industrial sector (see Figure 1).
Industrial boilers for heat and steam are another significant user of natural gas, and, while some are fueled by coal or other fuel, the dominant fuel source is natural gas. Boilers are commonly used for a variety of purposes by chemical manufactures, food processors, pulp and paper manufactures, and the petroleum and coal derivatives industries (including chemicals, coke, and coal tar). Twenty-two percent of the natural gas used in manufacturing is consumed in boilers. As with process heating, industrial boilers are dependent on natural gas, with 83 percent of boilers running on the fuel (Figure 2).
Often, power generation and process heating can be more efficiently accomplished by coproducing heat and power from a single unit with technology commonly called combined heat and power (CHP). Additional efficiencies and emission reductions are also achieved through the generation of electricity onsite, because it avoids transmission loss. In 2010, 14 percent of natural gas used in manufacturing was consumed by CHP and other power systems. As illustrated in Figure 2, natural gas dominates the fuel used for CHP. Nationwide, the added efficiencies of CHP systems avoid the annual emission of 35 million metric tons of CO2e.
|Figure 2: Direct Consumption of Fuels in the Industrial Sector|
CHP & Other Power
|Source: EIA Manufacturing Energy Consumption Survey (MECS), 2010|
For the chemicals industry, natural gas also serves a unique function, providing a chemical feedstock in the form of methane and liquids found in the natural gas, including ethane, propane, and butane. These liquids, especially ethane, are processed and transformed to become additional intermediate and final products. Chemical companies are particularly heavy users of natural gas as a feedstock and may consume up to two-thirds of their delivered natural gas for this purpose. While U.S. companies are reliant on low-cost natural gas liquids as a feedstock, European competitors use more expensive, oil-based naphtha. In 2010, for example, domestic ethane sold at half the price of imported naphtha in Europe, and, consequently, U.S. chemical manufactures have reaped a competitive advantage in international markets for intermediate and final goods. The emissions implications of using natural gas as a feedstock are very different from its other uses because feedstock use transforms hydrocarbon molecules into other products, rather than combusting them. Consequently, when natural gas is used as a feedstock, very few greenhouse gases are emitted.
Potential for Expanded Use in the Industrial Sector
Increased availability and low prices of natural gas have significant implications for domestic manufacturing, which has historically been concerned about supply availability and price volatility. Recently, abundant supply and low prices have led to an increase in domestic manufacturing, creating new jobs and economic value. Numerous companies have cited natural gas supply and price in announcing plans to open new facilities in the chemicals, plastics, steel, and other industries in the United States. In the past few years, the number of firms disclosing the positive impact of new gas resources for facility power generation and feedstock use to the Securities and Exchange Commission has increased substantially. In 2010, exports of basic chemicals and plastics increased 28 percent from the previous year, yielding a trade surplus of $16.4 billion. If the expectation that low prices will continue is correct, these economic benefits would be significant over the long term. A study by the American Chemistry Council, for instance, estimates that a 25 percent increase in ethane supplies would yield a $32.8 billion increase in U.S. chemical production. Industry, however, needs more than just abundance and low prices to maintain use of natural gas. Price stability is necessary to encourage long-term investments in industry, and increased natural gas supplies also have the potential to stabilize prices.
|Figure 3: CHP versus Conventional Production|
|Source: EIA Manufacturing Energy Consumption Survey (MECS), 2010|
Potential for Industrial Sector Emission Reductions
If supply remains robust and prices low and stable, the U.S. industrial sector is likely to reap substantial economic benefits from the increased availability of low-cost natural gas. Even as the sector expands, there are opportunities to reduce its emission intensity. Improving the efficiency of industrial boilers is one such opportunity. Boilers tend to have a low turnover rate, and very often older units are less efficient than newer ones. The pre-1985 fleet of boilers has an efficiency rate of between 65 percent and 70 percent; while new boilers have efficiency rates of between 77 percent and 82 percent and new, super–high-efficiency units can reach efficiency rates of up to 95 percent.
A Massachusetts Institute of Technology (MIT) analysis found that replacing older natural gas boilers with high-efficiency or super-high-efficiency units would decrease CO2 emissions by 4,500 to 9,000 tons or more per year per boiler. The analysis also found a strong economic incentive to make these replacements, highlighting annualized monetary savings of 20 percent (given certain assumptions, including 2010 natural gas prices) with a payback period of 1.8 to 3.6 years for the new equipment.
|Figure 4: Projected Natural Gas Consumption (2009-2035) in…|
Projected Total Industrial Consumption of Natural Gas for Heat and Power
Projected Energy Consumption of Natural Gas for Heat and Power per Dollar of Shipments
Projected Total Industrial Consumption of Natural Gas Liquids Feedstock
Projected Energy Consumption Natural Gas Liquids Feedstock per Dollar of Shipments
Projected Total Industrial CHP Generation for All Fuels through 2035
|Source: EIA AEO 2012 Early Release, 2012|
While natural gas is the most commonly used fuel source for industrial boilers, 17 percent of boilers use coal or other fuels, as shown in Figure 2. Because of the air pollutants from these coal-fired boilers, these boilers are now subject to the Environmental Protection Agency’s (EPA) 2012 Mercury and Air Toxics Standards. MIT conducted a separate analysis to determine the results of replacing the affected coal boilers with efficient or super-high-efficiency natural gas boilers (these natural gas boilers are not regulated under the new EPA rule). This analysis found that replacement with natural gas boilers would reduce annual CO2 emissions by about 52,000 to 72,000 tons per year per boiler.
Increasing the use of CHP also has potential to reduce emissions. A 2008 Oak Ridge National Laboratory (ORNL) study analyzed the total U.S. energy system and calculated that increasing CHP’s share of total U.S. electricity generation capacity from 9 percent in 2008 to 20 percent by 2030 would lower U.S. GHG emissions by 600 million metric tons of CO2 compared to business as usual. Another study, by McKinsey & Company in 2009, sought to estimate the potential for expanding CHP by 2020 through net present value-positive investments. McKinsey estimated that the potential exists in the United States for an additional 50.4 GW of CHP capacity by 2020, which would avoid an estimated 100 million metric tons of CO2 emissions per year compared to business as usual. McKinsey found that 70 percent of the potential cost-effective incremental CHP capacity was through large-scale industrial cogeneration systems greater than 50MW.
While CHP results in few GHG emissions, barriers currently limit its application. Utilities often cite safety concerns as a barrier to deployment, particularly a fear of miscommunication between CHP operators and utilities in the event of an emergency, which utilities say could lead to dangerous situations where line workers are not certain whether lines are energized or not. Utilities may also have concerns about liability and risk associated with the interconnection between CHP operations and the grid, as utility employees may be affected by safety and technical decisions of CHP operators made independent of utilities. Like issues of safety, many utilities are concerned about the need to provide backup power to industrial facilities in case CHP systems are taken offline or are otherwise unavailable. For utilities, the ability to provide backup power to these facilities requires investments in capacity, and to pay for this capacity, utilities often charge higher, discriminatory rates and interconnection fees to CHP operators to compensate for these necessary investments.
In addition to these concerns, regulatory and corporate policies have inhibited the growth of CHP capacity. Power sector regulation in many states leads many utilities to view CHP as unprofitable and, accordingly, discourages its use. However, some innovative policy approaches can overcome this problem. One approach is decoupling, which eliminates the connection between utility sales volume and profitability. By doing so, decoupling makes CHP measures profitable to utilities, and, therefore, more likely to gain their support. Another potential policy solution is the implementation of lost-revenue adjustment policy, which compensates utilities for revenues lost because of efficiency measures. It allows utilities to collect a charge from customers to account for efficiency-related revenue losses. Lost-revenue adjustment policies also have the potential to encourage CHP. Other policy options include state incentives designed to encourage the use of CHP. State-level policies include standardizing interconnection guidelines, tax incentives, and inclusion of CHP as a compliance mechanism for clean energy standards. Some states have enacted these policies, but, as with many state-led policies, there is a diversity of approaches to, and success with, implementation.
Last week, the Union of Concerned Scientists released a new report, A Climate of Corporate Control: How Corporations Have Influenced the U.S. Dialogue on Climate Science and Policy. It’s an important topic, as we know there are professional merchants of doubt whose sole purpose is to exaggerate scientific uncertainty on environmental issues where in fact the science is quite clear. As the report points out, we have seen this time and again with topics such as tobacco, leaded gasoline, SO2, asbestos, DDT, and now climate change.
Here’s how the authors describe their aim: “…Ultimately, we seek a dialogue around climate science and policy that prioritizes peer-reviewed scientific information over the agendas of specialized interest groups.” That’s a goal we at C2ES certainly share. And toward that end, we’d encourage a somewhat more nuanced and realistic perspective on how companies behave and why. Let me explain.
A Senate Transportation Committee hearing tomorrow will be the latest show of ire against the European Union’s effort to regulate greenhouse gas emissions from international aviation through its mandatory Emission Trading System (EU ETS). From Beijing to Delhi to Washington, governments claim the EU’s unilateral move violates international aviation law.
Indeed, in Washington, this is one of the rare issues these days where Democrats and Republicans find themselves on the same side opposing the EU’s action. The Obama Administration has weighed in with a strongly worded letter from Secretaries Clinton and LaHood urging the EU to drop its unilateral efforts and to work through the International Civil Aviation Organization (ICAO) to reduce aviation sector emissions.
But if tomorrow’s hearing before the Senate Transportation Committee is simply another round of EU-bashing, it will be a missed opportunity to focus on the one solution that virtually everybody (including the EU) appears to support—effective action by ICAO. Frustrated by years of inaction within ICAO, the real motivation behind the EU’s move may be to reignite efforts to reach agreement within ICAO.
June 6, 2012
Contact: Rebecca Matulka, 703-516-4146, firstname.lastname@example.org
Report Highlights Climate Change Risks to Key Gulf Coast Industries
Recommends Steps to Reduce Impacts on Region’s Energy and Fishing Sectors
Climate change is already having major impacts on the Gulf Coast region and action is needed to protect its vital industries from the likely impacts of continued warming, according to a new report from the Center for Climate and Energy Solutions (C2ES).
The report, Impacts and Adaptation Options in the Gulf Coast, examines the risks that climate change poses to the region’s energy and fishing industries, and to its residents and local governments. It concludes that climate impacts are already being felt across these sectors, and outlines measures that can be taken to adapt to the growing risks, reducing the region’s vulnerability and the costs associated with future impacts.
The convergence of several geographical characteristics—an unusually flat terrain both offshore and inland, ongoing land subsidence, dwindling wetlands, and fewer barrier islands than along other coasts—make the Gulf Coast region especially vulnerable to climate change. Among the impacts and risks cited in the report:
- Over the past century, both air and water temperatures have been on the rise across the region;
- Rising ocean temperatures heighten hurricane intensity, and recent years have seen a number of large, damaging hurricanes;
- In some Gulf Coast locations, local sea level is increasing at over ten times the global rate, increasing the risk of severe flooding; and
- Saltwater intrusion from rising sea levels damages wetlands, an important line of coastal defense against storm surge and spawning grounds for commercially valuable fish and shellfish.
“Nowhere else in the U.S. do we see the same convergence of critical energy infrastructure and high vulnerability to climate change,” said C2ES President Eileen Claussen. “These risks are not borne by the Gulf Coast alone. A major energy supply disruption, for instance, would be felt nationwide. We must respond on two fronts: We have to work harder to reduce the greenhouse gas emissions causing climate change. And we must take steps, in the Gulf Coast and elsewhere, to prepare for the impacts that can’t be avoided.”
The report’s lead author is Hal Needham, a researcher at Louisiana State University’s Southern Climate Impacts Planning Program (SCIPP) and an expert on hurricane storm surges in the Gulf Coast. The co-authors are David Brown, an assistant professor in LSU’s Department of Geography and Anthropology, and Lynne Carter, associate director of SCIPP.
In their analysis of the Gulf Coast’s energy industry, which comprises about 90 percent of the region’s industrial assets, the authors found significant risks from hurricanes, sea level rise, rising temperatures and drought. The report noted the considerable damage the energy industry sustained from recent hurricanes in 2004, 2005 and 2008. Thirty percent of the nation’s refineries are located in Texas and Louisiana, and Louisiana Offshore Oil Port in Port Fourchon is the country’s only deep-water oil import facility. At its current elevation, Louisiana Highway 1, the only access to the port, is projected to be flooded 300 days a year by 2050.
For the region’s other major industry, fishing, the report details major infrastructure risks, especially relating to coastal docking and fish processing. Fish and shellfish populations are also vulnerable to climate impacts, with a combination of warmer water, ocean acidification, and excessive runoff from the Mississippi River combining to increase the risk of large-scale changes in the Gulf ecosystem.
The authors emphasize that advance planning can reduce the region’s vulnerability and the costs incurred from future climate impacts.
For the energy sector, adaptation strategies include learning from recent hurricanes to more rigorously assess vulnerabilities; strengthening design standards for drilling platforms and other infrastructure; and undertaking projects such as the planned raising of sections of Highway 1 to Port Fourchon. To reduce vulnerability in the fishing industry, options include strengthening docking facilities and other infrastructure subject to storm surges, and limiting fertilizer use upstream on the Mississippi River to reduce the incidence of hypoxia (oxygen-starved waters) in the Gulf.
“Climate change is already taking a toll on the Gulf Coast, but if we act now to become more resilient, we can reduce the risks, save billions in future costs, and preserve a way of life,” said Needham. “The Gulf Coast is one of the first regions to feel the impacts of climate change. It only makes sense to be a first mover on climate adaptation as well.”
The Center for Climate and Energy Solutions (C2ES) is an independent non-profit, non-partisan organization promoting strong policy and action to address the twin challenges of energy and climate change. Launched in November 2011, C2ES is the successor to the Pew Center on Global Climate Change, long recognized in the United States and abroad as an influential and pragmatic voice on climate issues. C2ES is led by Eileen Claussen, who previously led the Pew Center and is the former U.S. Assistant Secretary of State for Oceans and International Environmental and Scientific Affairs.
Impacts and Adaptation Options in the Gulf Coast
by Hal Needman, David Brown, and Lynne Carter
The central and western U.S. Gulf Coast is increasingly vulnerable to a range of potential hazards associated with climate change. Hurricanes are high-profile hazards that threaten this region with strong winds, heavy rain, storm surge and high waves. Sea-level rise is a longer-term hazard that threatens to exacerbate storm surges, and increases the rate of coastal erosion and wetland loss. Loss of wetlands threatens to damage the fragile coastal ecosystem and accelerates the rate of coastal erosion.
These hazards threaten to inflict economic and ecological losses in this region, as well as loss of life during destructive hurricanes. In addition, they impact vital economic sectors, such as the energy and fishing industries, which are foundational to the local and regional economy. Impacts to these sectors are also realized on a national scale; Gulf oil and gas is used throughout the country to heat homes, power cars, and generate a variety of products, such as rubber and plastics, while seafood from the region is shipped to restaurants across the country.
This report reviews observed and projected changes for each of these hazards, as well as potential impacts and adaptation options. Information about the scale and relative importance of the energy and fishing industries is also provided, as well as insight into potential vulnerabilities of these industries to climate change. This report also identifies some adaptation options for those industries.
Analysis for Carbon Dioxide Enhanced Oil Recovery: A Critical Domestic Energy, Economic, and Environmental Opportunity Detailed Methodology and Assumptions
The Center for Climate and Energy Solutions (C2ES) and the Great Plains Institute (GPI) conducted an analysis, with extensive input from the participants of National Enhanced Oil Recovery Initiative (NEORI), to inform NEORI’s recommendations for a federal production tax credit to support enhanced oil recovery with carbon dioxide (CO2-EOR). In particular, C2ES and GPI explored the implications of the recommendations for CO2 supply, oil production and federal revenue. This document describes the research, assumptions, and methodology used in the analysis.
C2ES and GPI compared the likely cost of a federal tax credit for greater CO2 capture and supply with the federal revenues expected from applying existing tax rates to the resulting incremental oil production. C2ES and GPI quantified two key relationships for CO2-EOR develop-ment and a related tax credit program:
- Cost gap – the difference between CO2 suppliers’ cost to capture and transport CO2 and EOR operators’ willingness to pay for CO2. The goal of the tax credit is to bridge the cost gap. Thus, the cost gap determines the expected level of the tax credit in a proposed competitive-bidding process.
- Revenue neutrality/revenue-positive outcome - the federal government will bear the cost of a CO2-EOR tax credit program, yet it will enjoy increased revenues from the expansion of CO2-EOR oil production when existing tax rates are applied to the additional production. C2ES and GPI analyzed when the net present value of expected revenues would equal or exceed the net present value of program costs.
C2ES and GPI calculated the tax credit required to bridge the cost gap, and the cost and revenue implica-tions. C2ES and GPI developed input assumptions based on real-world physical and market conditions after consulting with NEORI participants and other industry experts and reviewing available literature. C2ES and GPI developed a core scenario based on “best guess” inputs and conducted several sensitivity analyses of key inputs. C2ES and GPI demonstrated that a program can be designed that will become “revenue positive” (defined as when the federal revenues from ad¬ditional new oil production exceed the cost of a carbon capture tax credit program after applying a discount rate to both costs and revenues) within ten years after tax credits are awarded. Sensitivity analysis reveals that the program remains revenue positive using a realistic range of likely assumptions.
My C2ES colleague, Judi Greenwald, will be testifying on Thursday at a hearing of the Senate Energy and Natural Resources Committee on the Clean Energy Standard Act of 2012, a bill written by Sen. Jeff Bingaman (D-NM), the committee chairman. As mentioned in my previous blogs (The Bingaman Clean Energy Standard: Let the Conversation Begin and The Bingaman Clean Energy Standard: What is "Clean"?) and in our primer on the design of a clean energy standard (CES), we think a CES holds a lot of potential for maintaining a diverse energy mix, advancing clean energy technology and associated industries, and reducing the environmental footprint of the electric power sector—including the sector's greenhouse gas emissions, which account for about one third of the U.S. total.
As Judi will attest, we also think Sen. Bingaman's bill is a great start, and balances the multiple objectives we would have for such a measure. On Thursday, we get to hear what a few other people think.
Watch this space Thursday morning as I live blog from the hearing and post updates below.
Update May 17, 11:58 am: It’s a standing-room-only crowd at this morning’s hearing before the Senate Energy and Natural Resources Committee on Senator Jeff Bingaman’s proposal for a federal clean energy standard.
Senators in attendance: Committee chairman Sen. Bingaman (D-NM), top committee Republican Sen. Murkowski (R-AK), Barrasso (R-WY), Cantwell (D-WA), Coons (D-DE), Corker (R-TN), Franken (D-MN), Manchin (D-WV), Risch (R-ID), Shaheen (D-NH), Udall (D-CO), Wyden (D-OR)
Here are some highlights of the question-and-answer session during the hearing’s first panel, with witnesses David Sandalow, Assistant Secretary for Policy and International Affairs at the U.S. Department of Energy, and Dr. Howard Gruenspecht, Acting Administrator of the Energy Information Administration:
Sen. Bingaman pointed out that EIA projects that electricity rates would increase by 2035 under the CES, but then asked how would electricity bills will be affected. Mr. Sandalow answered that the modeling shows that the average household energy bill would actually decline by $5 a month by 2035, in large part because of the energy efficiency promoted by the bill. Dr. Gruenspecht agreed.
Sen. Murkowski asked whether the cost of renewable energy being used by federal agencies under the Energy Policy Act of 2007 is an indication of the costs that would be seen under Sen. Bingaman’s bill. Mr. Sandalow pointed out that a key difference between Sen. Bingaman’s bill and the 2007 law is that the CES would give credit not only for renewable energy, but for nuclear power, natural gas, and clean coal, which would lead to lower prices than renewable energy alone.
Sen. Barrasso asked whether the Obama administration would rescind greenhouse gas regulations promulgated under the Clean Air Act if Sen. Bingaman’s bill were enacted. Mr. Sandalow said the administration would not support such an amendment to the Clean Air Act. For the record, C2ES believes that if a CES, or any other measure, led to significant reductions in GHG emissions from a given economic sector, we should be open to using that measure rather than the existing provisions of the Clean Air Act that pertain to that sector.
Sen. Franken suggested that it might be worth setting aside a fraction of the bill’s requirement for clean energy specifically for renewable energy. In fact, while most states have renewable energy standards in place, four—Michigan, Ohio, Pennsylvania, and West Virginia—have alternative energy standards, similar to Sen. Bingaman’s clean energy standard proposal, and each of the four takes an approach that favors renewable energy sources over the other qualifying clean energy sources.
Update May 17, 1:55 pm: Here are some quick notes on the second panel of this morning’s hearing. The room is still full even though many of the Senators and journalists have left—thus missing a discussion on preemption that was arguably the most noteworthy exchange of the entire hearing.
After the opening statements, Senators Bingaman and Murkowski had an extended back-and-forth with the panelists about the overlap between the Bingaman bill and other regulatory programs. The panelists offered a range of views, with a couple supporting preemption of the Clean Air Act authority. C2ES’s Judi Greenwald expressed a more nuanced view:
The key issue is environmental results. If a CES is ambitious enough, and can achieve greater environmental benefits than we can get under existing Clean Air Act Authority, it might make sense to consider replacing some Clean Air Act provisions with a CES. However, we need to be very cautious. The Clean Air Act has very broad authority to address GHG emissions throughout the economy and the CES only applies to power plants. We would need to ensure that EPA maintains its authority to continue to make progress in other sectors, for example, as with the successful greenhouse gas standards for vehicles.
Perhaps the biggest obstacle to exploring this issue is the deep partisan divide over EPA and the Clean Air Act. With members of Congress calling for an evisceration of EPA and the Clean Air Act, there is a legitimate concern that opening up the Act for an ostensibly narrow revision would lead to a gutting of provisions having nothing to do with greenhouse gases.
On another topic, Sen. Franken discussed Minnesota’s energy efficiency resource standard, and asked whether incentives for energy efficiency could be incorporated into the Bingaman bill. Judi Greenwald pointed out that many of the bill’s features would indeed promote energy efficiency: crediting of combined heat and power, the use of revenues raised through the alternative compliance payment, and the very structure of the proposed standard—it would be set as a percentage of total electricity production; if electricity use goes down, the requirement is easier to meet.
One thing we wish we could've said:
During the first panel, Sen. Corker said carbon capture and storage (CCS) will be broadly deployed when donkeys fly. Sen. Manchin, who takes a decidedly more favorable view towards CCS, was nevertheless concerned that the bill does not promote CCS.
Here's what we would have said, had they raised those points during the second panel:
While EIA projects that CCS is not deployed under the bill, it could be. CCS could play a bigger role under this bill if we can bring down its costs. There are a number of options for doing that. For example, C2ES co-convenes the National Enhanced Oil Recovery Initiative, which is calling for a federal tax credit to capture and transport CO2 from power plants and industrial sources for use in enhanced oil recovery. In addition to driving a lot of domestic oil production, and reducing CO2 emissions, it would generate additional revenue to cover the cost of CCS. We would expect that as CCS costs come down, it would enable coal to have a bigger role. A CES could help in other ways as well. AEP put the Mountaineer project on hold and withdrew from its partnership with DOE on this project because regulators in several states could not justify the expense for a technology that is not required by law. The CES could make the case for projects like Mountaineer to go forward.