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    Monday, February 17, 2014


    Changing the Game? Emissions and Market Implications of New Natural Gas Supplies

    September 2013 (Energy Modeling Forum/Stanford University)

    Study Highlights

    This study evaluates the channels through which shale formations and new natural gas supplies can change energy, economic and environmental opportunities within North America. It concludes that continued shale gas development within North America is likely to have more sweeping impacts on future energy prices than on the economy or the environment. This evaluation was conducted by a working group of 50 experts and advisors from a range of diverse universities, research institutes, corporations and government agencies. Support for the study’s conclusions came from 14 different expert teams using their own energy-economy models.

    Natural gas producers currently receive about $4 per thousand cubic feet, up from about $2.50 about a year ago. Baseline projections in the study anticipate some upward drift in prices that range between $4.03 and $6.24 by 2020 across the models even after adjusting for inflation. More optimistic supply conditions, however, should reduce this price range to $2.67 and $4.95 by lowering production costs.

    The upward drift in prices expected by most groups reflects a market where demand for natural gas slowly catches up to the robust supplies of shale gas that have been recorded since 2006.

    If the economy should grow faster than anticipated, natural gas prices will be higher but only modestly so. Prices are no more than $0.41 higher by 2020 in any model if the economy grows by 3.0 percent annually rather than 2.5 percent. Additional consumption is not expected to add greatly to the costs of producing more natural gas.

    The study underscores that relying upon a single forecast can be very risky. Instead, the study often discusses the impacts in terms of ranges found across the various models. Each expert team holds very different views on fundamental supply and demand conditions that shape the future path for natural gas and competitive fuels.

    Shale development also boosts the economy by $70 billion annually over the next several decades. Although this amount appears large, it represents a relatively modest 0.46 percent of the US economy. Today total natural gas expenditures represent about one percent of GDP within this country.

    Shale development has relatively modest impacts on carbon dioxide, nitrogen oxide and sulfur dioxide emissions, particularly after 2020. Since 2006, electricity generation has become less carbon intensive as its natural gas share increased from 16 to 24 percent and its coal share decreased from 52 to 41 percent. Over future years, this trend towards reducing emissions becomes less pronounced as natural gas begins to displace nuclear and renewable energy that would have been used otherwise in new powerplants under reference case conditions.

    Another contributor to the modest emissions impact is the somewhat higher economic growth that stimulates more emissions. Reinforcing this trend is the greater fuel and power consumption resulting from lower natural gas and electricity prices.


    Overall shale gas development and use across the breadth of scenarios analyzed have relatively modest impacts on the emissions of carbon dioxide, sulfur dioxide and nitrogen oxides. The implications for carbon dioxide are mixed and depend very much on the model and specific assumptions about the growth of coal, nuclear and renewable energy. It causes small reductions in damages coming from the other two emissions.

    Natural gas has lower emissions of carbon dioxide, sulfur dioxide and nitrogen oxides at the burnertip than coal and oil. This substitution will decrease total downstream emissions but other factors caused by more available natural gas may offset it. These effects include higher GDP, more energy use and the displacement of sources with fewer emissions like renewable and nuclear energy.

    This section reviews the results for carbon dioxide emissions in greater detail. It compares by model the growth trends for different shale supply conditions with those under a carbon-cost constraint case. The latter scenario provides a useful benchmark for considering the different shale supply cases but is not meant to be a normative policy case. It is well understood that combined action on multiple greenhouse gases is more efficient than focusing upon carbon dioxide alone when mitigating climate change.

    This case describes an energy market where politicians adopt a series of unspecified policies that gradually raises the cost of using fossil fuels that are carbon intensive. Although these costs could be passed along through carbon taxes or tradable permits, they could also result from other programs that restrict carbon-based energy sources. These programs are implemented in 2013 and are not allowed to cost more than $25 (2010 dollars) per tonne of carbon dioxide emissions. Over time, they become more severe with inflation-adjusted costs that increment by 5 percent per year to reach $75 (2010 dollars) in 2035. These additional costs discourage the use of carbon-intensive fuels but do not transfer funds towards the government.

    Figures 11, 12 and 13 show the annual growth trends covering the 2010-2020, 2010-2035 and 2010-2050 periods, respectively. The bars display total carbon dioxide emissions by model in three separate scenarios: low-shale (light blue bars), high-shale (dark blue bars) and carbon-price (green bars) conditions. In any of the three periods, the difference between the high-shale and low-shale cases is relatively small. Emission growth rates for the reference case are not shown because they track closely those for the two-shale cases. In contrast, emission growth rates for the carbon- price case lie well below the other trends.

    The carbon dioxide emission differences due to shale supply conditions are not only smaller than those due to carbon-price impacts, but they are also not uniformly lower in each model for the high-shale relative to the low-shale conditions. In any period some models show a higher emissions growth and other models show a lower emissions growth in the high-shale case.

    Whereas Figures 11, 12 and 13 show the rate of growth in emissions in individual cases, it is easier to understand the impact of shale supply on the carbon dioxide trends by decomposing the change in emissions due to different effects. Appendix D provides a more thorough decomposition to show the separate effects of greater GDP, improving primary energy intensity (Btu per dollar of GDP), and the decarbonization of primary energy supply (tonnes of carbon dioxide emissions per Btu). Figure 14 displays a simpler segmentation that underscores the same principles. The change in carbon dioxide emissions due to high-shale supplies for the 2010-2035 period is shown for each model by the dark blue bar. The models are ordered by this variable, with the largest declines appearing on the left side of the figure. The green bar indicates the decarbonization of the primary fuel supply in each model. This bar will be more negative when natural gas replaces coal or oil rather than carbon-free sources. The third, light blue bar represents the increase in primary energy use when natural gas is less expensive. This bar will be more positive when the economy grows more and when energy consumption increases in response to lower natural gas and electricity prices.

    Most projections indicate that primary energy will become more decarbonized when natural gas is more available. The one important exception is USREGEN, which expects aggregate energy to become more carbonized as natural gas retards the growth of new nuclear plants.

    Decarbonization is the dominant effect in determining carbon dioxide emissions for the projections shown on the left. These models have relatively small expansions in primary energy use due to either economic growth or increasing energy intensity. The four models on the left side are process models that emphasize the competition between explicit technologies for meeting final energy service demands. Although some models like the LIFT-MARKAL framework incorporate a large inter-industry macroeconomic model, these frameworks focus considerable attention on the competition between technologies.

    The expansion in primary energy use is the dominant effect in determining carbon dioxide emissions for the projections shown on the right. These models have relatively small decarbonization effects. The three models on the right side are inter-industry, economic equilibrium frameworks that emphasize economic factors and the interrelationships between different markets and sectors within the economy. Although these models are coupled with process models for the electric utility sector, these frameworks focus considerable attention on economic forces and the role for prices.

    Models appearing in the center of this figure combine economic factors and explicit technologies. They show more moderate impacts on carbon dioxide emissions.

    Comparisons with the carbon-price case are useful. Identical in format to Figure 14, Figure 15 summarizes the 2035 impacts of carbon pricing when reference conditions prevail. Notice that both decarbonization and the primary energy effect both place large downward pressure on carbon dioxide emissions for most models. The major difference from Figure 14 is twofold. First, carbon dioxide emissions fall much more precipitously below the reference case path in Figure 15. And second, the introduction of a carbon price reduces primary energy use through both economic growth and energy intensity rather than increases it. The light blue bars in Figure 15 extend downward rather than upward.

    Although shale expansion reduces carbon dioxide emissions in some models, its impacts are not the same as an integrated climate policy if the public is concerned about global climate change risks over the long run.

    Market Expansions and Natural Gas Prices

    Natural gas prices are currently low relative to the costs for other fuels. Many potential users are reluctant to invest in new capital equipment and infrastructure, however, because they fear that expanding demand can significantly raise future natural gas prices. If energy producers can easily extract additional supplies without much additional cost, future natural gas prices may not escalate quickly as new demands enter the market. Conversely, prices may rise quickly if producers find that new supplies are costly and future production from existing wells decline rapidly.

    The study included several cases when the annual economic growth rate increased from 2.7 to 3.2 percent. The faster economic growth rate influenced certain key manufacturing sectors more than other sectors. For example, the chemical industry in the faster growth case grew proportionally faster than other industries at an annual rate of 1.5 rather than 1.2 percent.

    Higher economic growth raises natural gas consumption above the reference path in all models. Figure 16 compares the average projection for these conditions with those for the high-shale, low-shale and reference conditions. The average high-growth consumption pattern tracks the high-shale consumption path quite closely through the 2010-2050 period. Average consumption rises in all four cases, even when natural gas production is constrained in the low-shale conditions.

    An additional economic growth of 0.5 percent per year raises the average wellhead price from $7 to about $7.50 in 2035. Natural gas prices rise above the reference path in all models but by varying amounts in the high-growth case. Figure 17 compares the average price projection for these conditions with those for the high-shale, low-shale and reference conditions. Even with some softening over the next five years, the average natural gas wellhead price rises over the full period in all four cases. This trend applies even for favorable technological and geological conditions in the high-shale case.

    It is interesting that the high-growth and high-shale conditions produce similar shifts in the average consumption paths but quite different price responses. The average high-growth price pattern in Figure 17 shifts upward from reference levels (the solid black line) by much less than the high-shale price pattern moves downward. Generally, prices do not rise as much in the high-demand projections because natural gas production tends to respond considerably less to changes in the price level than does consumption.

    These trends can be observed from Figure 18, which compares the response of each model’s natural gas supply and demand to price changes as derived from a comparison of scenario results for 2035. Results from the high-shale case are compared to their counterparts in the reference scenario to derive the demand response of total consumption to changes in the wellhead price. Results from the high-growth case are compared to their counterparts in the reference scenario to derive the demand response of total consumption to changes in the wellhead price. Results from the high-growth case are compared to their counterparts in the reference scenario to derive the supply response of total U.S. production and imports to changes in the wellhead price. These responses are reported as inferred price elasticities that show the ratio of the percentage change in total natural gas use or availability to the percentage change in wellhead prices, where an estimate of 0.5 indicates that the percent change in supply or demand amounts to half of the percent change in wellhead price. The derived supply response in some models appears very high because their results reveal very small price changes due to high economic growth that may be misleading for computing elasticities. For this reason, the figure truncates any large responses at the value, two. See Appendix E for further review.

    Higher exports also increase the demand for natural gas, although its impact can be somewhat different from the high-growth case. The study included a high-export case patterned after one set of conditions evaluated by the U.S. Energy Information Administration (2012). Beginning in 2015, exports gradually expanded by one billion cubic feet per day until the increase reached six billion cubic feet per day in 2020. The 2020 expansion represents about 10 percent of a total market comprising 22 trillion cubic feet annually. Modelers allowed these exports to occur regardless of world market conditions.

    Although only three models simulated these conditions, their results suggest modest natural gas price increases due to an expanding export market. Wellhead prices are 2.5 to 9 percent higher in 2020, resulting in price increments between $0.14 and $0.39 per Mcf in 2010 dollars. Estimates range between 2.6 and 6.3 percent ($0.17 to $0.33) in 2025 and 2.8 and 7.1 percent in 2030 ($0.20 to $0.48).

    The study also evaluated several advanced end-use natural gas technologies in another high-demand case. These cases were simulated by the process models with explicit technologies that included the following five models: CIMS-US, EPA-IPM, LIFT-MARKAL, MARKAL-EPAUS9r and US National MARKAL. Lower costs increased potential natural gas use by options primarily in the transportation sector, such as LNG trains and heavy-duty trucks. The scenario also included more favorable economic conditions for gas-to-liquid (GTL) processes that manufactured diesel fuel from natural gas. It also evaluated some additional advancements for stationary fuel cells providing heat and power in residential and commercial buildings. Average natural gas use for transportation increased gradually to 1.1 quads (approximately 3.1 billion cubic feet per day) by 2035 as a result of these higher potentials. Projections ranged from near zero to 2.9 quads across the five models…


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