# Annual Energy Outlook 2012

Release Date: June 25, 2012 | Next Early Release Date: January 23, 2013 | Report Number: DOE/EIA-0383(2012) 

# Issues in Focus

Introduction The "Issues in focus" section of the Annual Energy Outlook (AEO) provides an in-depth discussion on topics ofspecial interest, including significant changes in assumpti ons and recent developments in technologies for ene rgy production and consumption. Detailed quantitative results are avai lable in Appendix D. The first topic updates a disc ussion included in the Annual Energy Outlook 2011 ( AEO2011 ) that compared the results of two cases with diffe rent assumptions about the future course of existing energy policies. One case assume s the elimination of sunset provisions in existing energy policies; that is, the policies are assumed not to sunset as they woul d under current law. The other case assumes the extension or expansion of a selected group of existing policies—corporate average fuel economy (CAFE) standards, appliance st andards, and production tax credits (PTCs)—in addition to the el imination of sunset provisions.
Other topics discussed in this section as identifie d by subsection number include (2) oil price and pr oduction trends in the Annual Energy Outlook 2012

( AEO2012

); (3) potential efficiency improvements and their impacts on end-use energy demand; (4) energy impacts of proposed CAFE standar ds for light-duty vehicles (LDVs), model years (MYs ) 2017 to 2025; (5) impacts of a breakthrough in battery vehicle te chnology; (6) heavy-duty (HD) natural gas vehicles (NGVs); (7) changing structure of the refining industry; (8) changing en vironment for fuel use in electricity generation; ( 9) nuclear power in AEO2012; (10) potential impact of minimum pipeline throughput constraints on Alaska North Slope oil pr oduction; (11) U.S. crude oil and natural gas resource uncertainty; and (12) evolving Marcellus shale gas resource estimat es.
The topics explored in this section represent curre nt and emerging issues in energy markets; but many of the topics discussed in AEOs published in recent years also re main relevant today. Table 5 provides a list of titles from the 2011, 2010, and 2009 AEOs that are likely to be of interest to today's read ers—excluding topics that are updated in AEO2012 . The articles listed in Table 5 can be found on the U.S. Energy Information Admini stration (EIA) website.



## 1. No Sunset and Extended Policies cases

Background The AEO2012

Reference case is best described as a "current law s and regulations" case, because it generally assumes th at existing laws and regulations will remain unchanged throughout the projection period, unless the legislation establishing them sets a sunset date or specifies how they will chang e. The Reference case often serves as a starting po int for the analysis of proposed legislative or regulatory changes. While t he definition of the Reference case is relatively s traightforward, there may be considerable interest in a variety of alternativ e cases that reflect the updating or extension of current laws and regulations. In that regard, areas of particular interest includ e:

 Laws or regulations that have a history of being ex tended beyond their legislated sunset dates. Exampl es include the various tax credits for renewable fuels and technol ogies, which have been extended with or without mod ifications several times since their initial implementation.

 Laws or regulations that call for the periodic upda ting of initial specifications. Examples include ap pliance efficiency standards issued by the U.S. Department of Energy ( DOE), and CAFE and greenhouse gas (GHG) emissions 

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8/9/2012 http://www.eia.gov/forecasts/aeo/IF_all.cfmstandards for vehicles issued by the National Highw ay Traffic Safety Administration (NHTSA) and the U. S.

Environmental Protection Agency (EPA).

 Laws or regulations that allow or require the appro priate regulatory agency to issue new or revised re gulations under certain conditions. Examples include the numerous p rovisions of the Clean Air Act that require the EPAto issue or revise regulations if it finds that an environmenta l quality target is not being met.

To provide some insight into the sensitivity of res ults to scenarios in which existing tax credits do not sunset, two alternative cases are discussed in this section. No attempt is made to cover the full range of possible uncertaint ies in these areas, and readers should not view the cases discussed as EIA projections of how laws or regulations might or sho uld be changed.



### Analysis cases The two cases prepared—the No Sunset and Extended P olicies cases—incorporate all the assumptions from the AEO2012
Reference case, except as identified below. Changes from the Reference case assumptions in these cases include the following.



### No Sunset case

 Extension through 2035 of the PTC for cellulosic bi ofuels of up to $1.01 per gallon (set to expire at the end of 2012).

 Extension of tax credits for renewable energy sourc es in the utility, industrial, and buildings sector s or for energyefficient equipment in the buildings sector, includ ing:

The PTC of 2.2 cents per kilowatthour or the 30-per cent investment tax credit (ITC) available for wind
, geothermal, biomass, hydroelectric, and landfill ga s resources, currently set to expire at the end of 2012 for wind and 2013 for the other eligible resources, are assu med to be extended indefinitely.

For solar power investment, a 30-percent ITC that i s scheduled to revert to a 10-percent credit in 201 6 is, instead, assumed to be extended indefinitely at 30 percent.
In the buildings sector, tax credits for the purcha se of energy-efficient equipment, including photovo ltaics (PV) in new houses, are assumed to be extended indefinitely , as opposed to ending in 2011 or 2016 as prescribe d by current law. The business ITCs for commercial-secto r generation technologies and geothermal heat pumps are assumed to be extended indefinitely, as opposed to expiring in 2016; and the business ITC for solar sy stems is assumed to remain at 30 percent instead of revertin g to 10 percent.

In the industrial sector, the ITC for combined heatand power (CHP) that ends in 2016 in the AEO2012 Reference case is assumed to be preserved through 2 035, the end of the projection period.



### Extended Policies case The Extended Policies case includes additional upda tes in Federal equipment efficiency standards that were not considered in the Reference case or No Sunset case. Residentia l end-use technologies subject to updated standards are not eligible for tax credits in addition to the standards. Also, the PTC for cellulosic biofuels beyond 2012 is not inc luded because the renewable fuel standard (RFS) program that is alrea dy included in the AEO2012 Reference case tends to be the binding driver of cellulosic biofuels use. Other than these exceptions, the Extended Policies case adopts the same assumptions as the No Sunset case, plus the following:

 Federal equipment efficiency standards are updated at periodic intervals, consistent with the provisio ns in the existing law, with the levels based on ENERGY STAR specifica tions, or Federal Energy Management Program (FEMP) purchasing guidelines for Federal agencies. Standar ds are also introduced for products that are not cu rrently subject to Federal efficiency standards.

 Updated Federal residential and commercial building energy codes reach 30-percent improvement in 2020 relative to the 2006 International Energy Conservation Code in the residential sector and the American Society of Heating, Refrigerating and Air-Conditioning Engineers Buildi ng Energy Code 90.1-2004 in the commercial sector. Two subsequent rounds in 2023 and 2026 each add an assu med 5-percent incremental improvement to building e nergy 

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The equipment standards and building codes assumed for the Extended Policies case are meant to illustr ate the potential effects of these policies on energy consu mption for buildings. No cost-benefit analysis or e valuation of impacts on consumer welfare was completed in develo ping the assumptions. Likewise, no technical feasib ility analysis was conducted, although standards were notallowed to exceed "maximum technologically feasibl e" levels described in DOE's technical support documents.

 The AEO2012

Reference, No Sunset, and Extended Policies cases include both the attribute-based CAFE standards for LDVs for MY 2011 and the joint attribute-based CAFE and vehicle GHG emissions standards for MY 201 2 to MY 2016. However, the Reference and No Sunset cases as sume that LDV CAFE standards increase to 35 miles p er gallon (mpg) by MY 2020, as called for in the Energ y Independence and Security Act of 2007 (EISA2007), and that the CAFE standards are then held constant in subseq uent model years, although the fuel economy of new LDVs continues to rise modestly over time.

The Extended Policies case modifies the assumption in the Reference and No Sunset cases by assuming th e incorporation of the proposed CAFE standards recent ly announced by the EPA and NHTSA for MY 2017 throu gh MY 2025, which call for an annual average increase in fuel economy for new LDVs of 3.9 percent. After 202 5, CAFE standards are assumed to increase at an average ann ual rate of 1.5 percent through 2035.

 In the industrial sector, the ITC for CHP is extend ed to cover all system sizes (limited to only capac ities between 25 and 50 megawatts in the Reference case), which may include multiple units. Also, the ITC is modified t o increase the eligible CHP unit cap from 15 megawatts to 25 megaw atts. These extensions are consistent with previous ly proposed or pending legislation.



### Analysis results The changes made to Reference case assumptions in t he No Sunset and Extended Policies cases generally lead to lower estimates for overall energy consumption, increased use of renewable fuels, particularly for electrici ty generation, and reduced energyrelated emissions of carbon dioxide ( CO 2 ). Because the Extended Policies case includes mostof the assumptions in the No Sunset case but adds others, the impacts in the Extended Policies case tend to b e greater than those in the No Sunset case. Although these cases show lo wer energy prices—because the tax credits and end-u se efficiency standards lead to lower energy demand and reduce th e cost of renewable fuels—consumers spend more on a ppliances that are more efficient in order to comply with the tigh ter appliance standards, and the Government receive s lower tax revenues as consumers and businesses take advantage of the t ax credits.



### Energy consumption

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Total energy consumption in the No Sunset case is c lose to the level in the Reference case (Figure 11). Improvements in energy efficiency lead to reduced consumption in this case, but somewhat lower energy prices lead to higher relative consumption, offsett ing some of the impact of the improved efficiency.

Total energy consumption growth in the Extended Policies case is markedly below the Reference case projection. In 2035, total energy consumption in th e Extended Policies case is nearly 6 percent below it s projected level in the Reference case. 

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### Buildings energy consumption

The No Sunset case extends tax credits for resident ial and commercial renewable energy systems and forthe purchase of energyefficient residential equipment. The Extended Policies case builds on the No Sunset case by assu ming updated Federal equipment efficiency standards and new stan dards forsome products that are not currently subject to st andards. For residential end-use technologies subject to standar ds, updated standards are assumed to replace any ex tension of incentives from the No Sunset case. Federal residen tial and commercial building energy codes are also improved as described above. Renewable distributed generation ( DG) technologies (PV systems and wind turbines) pro vide much of the buildings-related energy savings in the No Sunset c ase. Extended tax credits in the No Sunset case spu r increased adoption of renewable DG systems, leading to 110 billion kil owatthours of onsite electricity generation in 2035 —more than four times the amount of onsite electricity generated in 2035 in the Reference case. Similar adoption of renewabl e DG takes place in the Extended Policies case. With the additional eff iciency gains from assumed future standards and mor e stringent building codes, delivered energy consumption for buildings i n 2035 is 6.8 percent (1.5 quadrillion Btu) lower i n the Extended Policies case than in the Reference case, a reduction nearlyfive times as large as the 1.4-percent (0.3 quadri llion Btu) reduction in the No Sunset case.

Electricity use shows the largest reduction relativ e to the Reference case, with buildings electricityconsumption 2.4 percent and 8.2 percent lower, respectively, in the No Suns et and Extended Policies cases in 2035. Space heati ng and cooling are affected by both assumed standards and building cod es, leading to significant savings in energy consum ption for heating and cooling in the Extended Policies case. In 2035, ene rgy use for space heating in buildings is 6.9 perce nt lower, and energy use for space cooling is 17.3 percent lower, in the Extended Policies case than in the Reference case. In addition to improved standards and codes, extended tax credits for PV prompt increased adoption, offsetting some o f the purchased electricity for cooling. New standards for televisi ons and for personal computers (PCs) and related eq uipment in the Extended Policies case lead to savings of 20.6 perc ent and 18.2 percent, respectively, in residential electricity use by this equipment in 2035 relative to the Reference case. R esidential and commercial natural gas use declines from 8.3 quadrillion Btu in 2010 to 7.9 quadrillion Btu in 2035 in the E xtended Policies case, representing a 6.2-percent r eduction from the Reference case in 2035.



### Industrial energy consumption The Extended Policies case modifies the Reference c ase by extending the existing industrial CHP ITC through the end of the projection period, expanding it to include all indu strial CHP system sizes, and raising the maximum credit t hat can be claimed from 15 megawatts of installed capacity to 25 megaw atts. These assumptions are based on the current pr oposals in H.R. 2750 and H.R. 2784 of the 112th Congress. The chang es result in 2.7 gigawatts of additional industrial CHP capacity over the Reference case level in 2035. Natural gas consu mption in the industrial sector (excluding refining ) increases from 7.3 quadrillion Btu in the Reference case to 7.4 quadri llion Btu in the Extended Policies case, a 1.6-perc ent rise. Electricity purchases are nearly unchanged in the Extended Poli cies case, as additional demand for electricity rel ative to the Reference case is fulfilled almost exclusively by increased g eneration from CHP.



### Transportation energy consumption The Extended Policies case modifies the Reference c ase and No Sunset case by assuming the incorporatio n of the CAFE standards recently proposed by the EPA and NHTSA fo r MY 2017 through 2025, which call for a 3.9-percen t annual average increase in fuel economy for new LDVs, with CAFE st andards applicable after 2025 assumed to increase a t an average annual rate of 1.5 percent through 2035. Sales of v ehicles that do not rely solely on agasoline internal combustion engine for both motive and accessory power (including those th at use diesel, alternative fuels, and/or hybrid ele ctric systems) play a substantial role in meeting the higher fuel economystandards, growing to almost 80 percent of new LDV sales in 2035, compared with about 35 percent in the Reference cas e.

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LDV energy consumption declines in the Extended 

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8/9/2012 http://www.eia.gov/forecasts/aeo/IF_all.cfmPolicies case, from 16.6 quadrillion Btu (8.9 milli on

barrels per day) in 2010 to 12.9 quadrillion Btu (7 .3 million barrels per day) in 2035, about a 20-per cent reduction from the Reference case in 2035. Petroleum and other liquids fuels consumption in the transportation sector dec lines in the Extended Policies case, from 13.8 million barrels per day in 2010 to 12.7 million barrels per day in 2035, comp ared to an increase in the Reference case to 14.4 million barrels per day (Figure 12).



### Renewable electricity generation

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The extension of tax credits for renewables through 2035 would, over the long run, lead to more rapid growth in renewable generation than in the Reference case. Wh en the renewable tax credits are extended without exte nding energy efficiency standards, as is assumed in the N o Sunset case, there is a significant increase in ren ewable generation in 2035 relative to the Reference case ( Figure 13). Extending both renewable tax credits and energ y efficiency standards (Extended Policies case) resul ts in more modest growth in renewable generation, because renewable generation in the near term is a signific ant source of new generation to meet load growth, and enhanced energy efficiency standards tend to reduce overall electricity consumption and the need for ne w generation resources.

In the No Sunset and Extended Policies cases, renew able generation more than doubles from 2010 to 2035 , as compared with a 77 -percent increase in the Reference case. In 2035, t he share of total electricity generation accounted for by renewables is between 19 and 20 percent in both the No Sunset and Extended Policies cases, as compared with 15 percent in the Reference case.

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In all three cases, the most rapid growth in renewa ble capacity occurs in the very near term, largely as t he result of projects already under construction or pl anned. After that, the growth slows through 2020 before pi cking up again. Some of the current surge of renewable capacity additions is occurring in anticipation of the expiration of Federal incentives within the next ye ar (for wind) or two (for other renewable fuels except sola r). Results from the No Sunset and Extended Policies ca ses indicate that, given sufficient lead time, a long-t erm extension of these expiring provisions could resultin the postponement of some near-term activity to better m atch projected patterns of load growth. With slow growth in electricity demand and the addition of capacity stimulated renewable resources already have been developed, leaving only less favorable sites that may require significant investment in transmission as well as o ther additional infrastructure costs. Starting arou nd 2020, significant new 

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8/9/2012 http://www.eia.gov/forecasts/aeo/IF_all.cfmsources of renewable generation also appear on the market as a result of cogeneration at biorefineries built primarily to

produce renewable liquid fuels to meet the Federal RFS, where combustion of waste products to produce electricity is an economically attractive option.

Between 2020 and 2025, renewable generation in the No Sunset and Extended Policies cases starts to inc rease more rapidly than in the Reference case, and, as a resul t, generation from nuclear and fossil fuels is redu ced from the levels in the Reference case. Natural gas represents the largest source of displaced generation. In 2035, electricit y generation from natural gas is 11 percent lower in the No Sunset ca se and 15 percent lower in the Extended Policies ca se than in the Reference case (Figure 14).



### Energy-related CO 2

### emissions In the No Sunset and Extended Policies cases, loweroverall energy demand leads to lower levels of ene rgy-related CO 2 emissions than in the Reference case. The Extended Policies case shows much larger emissions reduction s than the No Sunset and Reference cases, due in part to the incl usion of tighter LDV fuel economy standards for MY 2017 through MY 2035. From 2010 to 2035, energy-related CO 2 emissions are reduced by a cumulative total of 4.3 billion metric tons (a 3.0- percent reduction over the period) in the Extended Policies case from the Reference case projection, a s compared with 0.9 billion metric tons (a 0.6-percent reduction over t he period) in the No Sunset case (Figure 15). The i ncrease in fuel economy standards assumed for new LDVs in the Extended Poli cies case is responsible for more than 40 percent of th e total reduction in CO 2 emissions in 2035 in comparison with the Reference case. The balance of the reduction in CO 2 emissions is a result of greater improvement in appliance efficiencies an d increased penetration of renewable electricity ge neration.

figure data

The majority of the emissions reductions in the No Sunset case result from increases in renewable elec tricity generation. Consistent with current EIA conventions and EPA practice, emissions associated with the combust ion of biomass for electricity generation are not count ed, because they are assumed to be balanced by carbon uptake when the feedstock is grown. A small reducti on in transportation sector emissions in the No Sunset ca se is counterbalanced by an increase in emissions from refineries during the production of synthetic fuels that receive tax credits. Relatively small incremental reductions in emissions are attributable to renewab les in the Extended Policies case, mainly because electric ity demand is lower than in the Reference case, reducin g the consumption of all fuels used for generation, including biomass.

In the residential sector, in both the No Sunset an d Extended Policies cases, water heating, space coo ling, and space heating together account for most of the emissions reductions from Reference case levels. In the commercial sector, only the Extended Policies case projects substantial reducti ons of emissions in those categories. In the indust rial sector, the Extended Policies case projects reduced emissions as a resul t of decreases in electricity purchases and petrole um use that are partially offset by increased reliance on natural g as—for example, increased use of natural gas fired industrial CHP.



### Energy prices and tax credit payments

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8/9/2012 http://www.eia.gov/forecasts/aeo/IF_all.cfmWith lower levels of overall energy use and more

consumption of renewable fuels in the No Sunset and Extended Policies cases, energy prices are lower t han in the Reference case. In 2035, natural gas wellhead price s are $0.44 per thousand cubic feet (6.6 percent) a nd $0.82 per thousand cubic feet (12.3 percent) lower in the No Sunset and Extended Policies cases, respectively, t han in the Reference case (Figure 16), and electricity prices are about 2 percent and 5 percent lower than in the Reference case (Figure 17).

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The reductions in energy consumption and CO2 emissions in the Extended Policies case are accompanied by higher equipment costs for consumers and revenue reductions for the U.S. Government. Fro m 2012 to 2035, residential and commercial consumers spend, on average, an additional $19 billion per ye ar (in 2010 dollars) for newly purchased end-use equipment
, distributed generation systems, and residential bui lding shell improvements in the Extended Policies case as compared with the Reference case. On the other hand
, they save an average of $22 billion per year on ene rgy purchases.

Tax credits paid to consumers in the buildings sect or (or, from the Government's perspective, reduced revenue) in the No Sunset case average $5 billion (real 2010 do llars) more per year than in the Reference case, which ass umes that existing tax credits expire as currently scheduled, mostly by 2016.
The largest response to Federal tax incentives for new renewable generation is seen in the No Sunset c ase, with extension of the PTC and the 30-percent ITC resulting in annu al average reductions in Government tax revenues of approximately $2.5 billion from 2011 to 2035, as compared with $520 mi llion per year in the Reference case. Additional re ductions in Government tax revenue in the No Sunset case resultfrom extensions of the cellulosic biofuels PTC. Th ese reductions increase rapidly from $52 million in 2013 to $7.2 b illion (2010 dollars) in 2035 (a cumulative total o f $75.1 billion) in comparison with the Reference case.


## 2. Oil price and production trends in AEO2012 The oil price in AEO2012 is defined as the average price of light, low-sulfur crude oil delivered in C ushing, Oklahoma, which is similar to the price for light, sweet crude oil, West Texas Intermediate (WTI), traded on the New Y ork Mercantile Exchange. AEO2012

also includes a projection of the U.S. annual aver age refiners' acquisition cost of imported crude oi l, which is more representative of the average cost of all crude oil s used by domestic refiners. Currently there is a p rice differential between WTI and similar-quality marker crude oils delivered to international ports via tanker (e.g., Brent and Louisiana Light Sweet crudes). The AEO2012 Reference case assumes that the large discrepancy will fade over time, as construction of more adequate pipeline capacity between Cushing and the Gulf of Mexico eases transportation of crude oil su pplies to and from U.S. refineries.
Oil prices are influenced by a number of factors, i ncluding some that have mainly short-term impacts. Other factors, such as the Organization of the Petroleum Exporting Countri es (OPEC) production decisions and expectations abo ut future world demand for petroleum and other liquids, affect pric es in the longer term. Supply and demand in the wor ld oil market are balanced through responses to price movements, and the factors underlying supply and demand expectatio ns are both numerous and complex. The key factors determining l ong-term supply, demand, and prices for petroleum a nd other liquids can be summarized in four broad categories: the eco nomics of non-OPEC supply, OPEC investment and prod uction 

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8/9/2012 http://www.eia.gov/forecasts/aeo/IF_all.cfmdecisions, the economics of other liquids supply, a nd world demand for petroleum and other liquids.

AEO2012

includes projections of future supply and demand f or "petroleum and other liquids." The term "petrole um" refers to crude oil (including tight oil from shale [also ref erred to as shale oil], chalk, and other low-permea bility formations), lease condensate, natural gas plant liquids, and refinerygain. The term "other liquids" refers to biofuels, bitumen (oil sands), coalto-liquids (CTL), biomass-to-liquids (BTL), gas-to- liquids (GTL), extra-heavy oils (technically petrol eum but grouped in "other liquids" in this report), and oil shale [ 41 ].



### Reference case The global oil market projections in the AEO2012 Reference case are based on the assumption that cu rrent practices, politics, and levels of access will continue in the near to mid-term. The Reference case assumes that continued robust economic growth in the non-Organization for Economi c Cooperative Development (OECD) nations, including China and India, will more than offset slower growth projecte d for many OECD nations. In the Reference case, non -OECD petroleum and other liquids consumption is about 21 million b arrels per day higher in 2035 than it was in 2010, but OECD consumption grows by less than 2 million barrels per day over t he same period. Total world consumption of petroleu m and other liquids grows to 106 million barrels per day in 2030 and 11 0 million barrels per day in 2035.

figure data

The Reference case also assumes that limitations on access to resources in many areas restrain the growth of non-OPEC petroleum liquids production over the projection period, and that OPEC production maintai ns a relatively constant share of total world petroleum and other liquids supply—between 40 and 42 percent. Wit h those constraining factors, satisfying the growing world demand for petroleum and other liquids in coming decades requires production from higher-cost resour ces, particularly for non-OPEC producers with technicall y challenging supply projects. In the Reference case, the increased cost of non-OPEC supplies, a constant OPE C market share, and easing of Cushing WTI infrastruct ure constraints combine to support average increases in real oil prices of about 5 percent per year from 2010 to 2020 and about 1 percent peryear from 2020 to 2035. In 2035, the average real price of crude oil in the Referenc e case is $145 per barrel in 2010 dollars (Figure 1 8). The rapid increase in the near term is based on the assumption that the W TI price will return to parity with Brent by 2016 a s current constraints on pipeline capacity between Cushing and the Gulf of M exico are eliminated.

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Increases in non-OPEC production of petroleum and other liquids in the Reference case come primarily from high-cost petroleum liquids projects in areas with inconsistent or unreliable fiscal or political regi mes and from increasingly expensive otherliquids projects that are made economical by rising oil prices and advances i n production technology (Figure 19). Bitumen producti on in Canada and biofuels production mostly from the Unit ed 

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the world's incremental supply of other liquids fro m 2010 to 2035 in the Reference case.



### Low Oil Price case In the Low Oil Price case, non-OECD economic growth is lower than in the Reference case, leading to sl ower growth in demand for petroleum and other liquids. Lower deman d, combined with greater access to and production of petroleum liquids resources, results in sustained lower oil prices. I n particular, the Low Oil Price case focuses on dem and in non-OECD countries, where uncertainty about future growth is much higher than in the mature economies of the OE CD. The Low Oil Price case assumes that oil prices fall steadily af ter 2011 to about $58 per barrel in 2017, then rise slowly to $62 per barrel in 2035. Growth in world demand for petroleum and othe r liquids is slowed by lower gross domestic product(GDP) growth in the non-OECD countries than is projected in the Ref erence case. Average annual GDP growth in the non-O ECD nations is assumed to be 1.5 percentage points lower than in t he Reference case, increasing by only 3.5 percent p er year from 2010 to 2035. As a result, non-OECD demand for petroleum an d other liquids in 2035 is 7 million barrels per da y lower than in the Reference case, and total world consumption in 2035 is 2 million barrels per day lower, at 107 million barrels per day.
In the Low Oil Price case, the market power of OPEC producers is weakened, and they lose the ability t o control prices and limit production. As a result, the OPEC market shar e of world petroleum and other liquids production i s 46 percent in 2035, as compared with 40 to 42 percent in the Reference case. Despite lower prices, non-OPEC levels of petr oleum liquids production are maintained until about 2020, as proj ects currently underway or planned are completed an d begin production. After 2020, non-OPEC petroleum liquids production d eclines as existing fields are depleted and not ful ly replaced by production from new fields and higher cost enhanced recovery technologies.
The Low Oil Price case assumes that technologies fo r producing biofuels, bitumen, CTL, BTL, GTL and ex tra-heavy oils achieve much lower costs than in the Reference case . As a result, production of those liquids increase s to 16 million barrels per day in 2035 despite significantly lower oil pri ces.


### High Oil Price case In the High Oil Price case, the assumption of high demand for petroleum and other liquids in the non-O ECD nations, combined with more constrained supply availability, results in higheroil prices than in the Reference case. Oil prices ramp up quickly to $186 per barrel (2010 dollars) in 2017 a nd continue rising slowly thereafter, to about $200 per barrel in 2035. The higher prices result from higher demand for petrole um and other liquid fuels in the non-OECD nations, resulting from the assumption of higher economic growth than in the Re ference case. Specifically, GDP growth rates for Ch ina and India in 2012 are 1.0 percentage point higher than in the Re ference case, and 0.3 percentage point higher in 20 35. For most other non-OECD regions, GDP growth rates average about 0. 5 percentage point above the Reference case in 2012 . For the OECD regions, where prices rather than a higher eco nomic growth rate are the main factor affecting dem and, consumption of petroleum and other liquids remains fairly flat over the projection.
On the supply side, OPEC countries are assumed to r educe their market share somewhat, to less than 41 percent through 2035. Non-OPEC petroleum liquids resources outside the United States are assumed to be less accessible and/or more costly to produce than in the Reference case, and h igher prices make other liquids supply more attract ive. In 2035, other liquids production totals 17 million barrels per da y in the High Oil Price case, about 4 million barre ls per day above the Reference case level, and other liquids account for15 percent of the total supply of petroleum and ot her liquids.


## 3. Potential efficiency improvements and their impacts on end-use energy demand In 2010, the residential and commercial buildings s ectors used 20.4 quadrillion Btu of delivered energ y, or 28 percent of total U.S. energy consumption. The residential sector acc ounted for 57 percent of that energy use and the co mmercial sector 43 percent. In the AEO2012 Reference case, delivered energy for buildings inc reases by a total of 9 percent, to 22.2 quadrillion Btu in 2035, which is modest relative to the rate o f increase in the number of buildings and their occ upants. In contrast, the U.S. population increases by 25 percent, commercial floorspace increases by 27 percent, and the numberof households increases by 28 percent. Accordingly, energy use in the buildings sector on a per-capita basis decline s in the projection. The 

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8/9/2012 http://www.eia.gov/forecasts/aeo/IF_all.cfmdecline of buildings energy use per capita in past years has been attributable in part to improvements in the efficiencies of

appliances and building shells, and efficiency impr ovements continue to play a key role in projections of buildings energy consumption.

Existing policies, such as Federal appliance standa rds, along with evolving State policies, and market forces, are drivers of energy efficiency in the United States. A number ofrecent changes in the broader context of the U.S. energy system that affect energy prices, such as advances in shale gas extraction and the economic slowdown, also have th e potential to affect the dynamics of energy efficiency improvement in th e U.S. buildings sector. Although these influences are important, technology improvement remains a critical factor fo r energy use in the buildings sector. The emphasis for this analysis is on fundamental factors, particularly technology factor s, that affect energy efficiency, rather than on po tential policy or regulatory options.

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Three alternative cases in AEO2012 illustrate the impacts of different assumptions for rates of technology improvement on delivered energy use in the resident ial and commercial sectors (Figure 20). These cases are in addition to the Extended Policies and No Sunset cas es discussed earlier, and they are intended to provide a broader perspective on changes in demand-side technologies. In the High Demand Technology case, high-efficiency technologies are assumed to penetra te end-use markets at lower consumer hurdle rates, wit h related assumptions in the transportation and indus trial sectors. In the Best Available Demand Technology ca se, new equipmentpurchases are limited to the most efficient versions of technologies available in the residenti al and commercial buildings sectors regardless of cost. In the 2011 Demand Technology case, future equipment purchases are limited to the options available in 2 011 ("frozen technology"), and 2011 building codes remain unchanged through 2035. Like the High Demand and Best Availab le Demand Technology cases, the 2011 Demand Technol ogy case includes all current Federal standards.

Without the benefits of technology improvement, bui ldings energy use in the 2011 Demand Technology cas e grows to 23.4 quadrillion Btu in 2035, as compared with 22.2 quad rillion Btu in the Reference case. In the High Dema nd Technology case, energy delivered to the buildings sectors only reac hes about 20 quadrillion Btu for any year in the pr ojection period, and in the Buildings Best Available Demand Technology case it declines to 17.9 quadrillion Btu in 2026 before rising slightly to 18.1 quadrillion Btu in 2035.



### Background The residential and commercial sectors together are referred to as the "buildings sector." The cases d iscussed here are not policy-driven scenarios but rather "what-if" cases used to illustrate the impacts of alternative techn ology penetration trajectories on buildings sector energy use. In a g eneral sense, this approach can be understood as re flecting uncertainty about technological progress itself, or uncertaintyabout consumer behavior, in that the market response to a new technology is uncertain. This type of uncertainty is being stu died through market research, behavioral economics, and related disciplines that examine how purchasers perceive options, diffe rentiate products, and react to information over ti me. By varying technology progress across the full range of end us es, the integrated demand cases provide estimates o f potential changes in energy savings that, in reality, are likely to b e less uniform and more specific to certain end use s, technologies, and consumer groups. Specific assumptions for each of t he cases are summarized in Tables 6 and 7

. 

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### Results for the residential sector

To emphasize that efficiency is persistent and its effects accumulate over time, energy use is discuss ed in terms of cumulative reductions (2011-2035) relative to a cas e with no future advances in technology after 2011. An extensive range of residential equipment is covered by Federal efficie ncy standards, and the continuing effects of those standards contribute to the cumulative reduction in delivered energy use of12.3 quadrillion Btu through 2035 in the Reference case relative to the 2011 Demand Technology case. Electricity and natura l gas account for more than 85 percent of the diffe rence, each showing a cumulative reduction greater than 5 quadrillion B tu over the period. Energy use for space heating sh ows the most improvement in the Reference case, affected by impr ovements in building shells and heating equipment ( Figure 21). Televisions and PCs and related equipment use 1.9 q uadrillion Btu less energy over the projection peri od, as devices with energy-saving features continue to penetrate the ma rket, and laptops continue to gain market share ove r desktop PCs.

figure data
Cumulative savings in residential energy use from 2 011 to 2035 total 31.6 quadrillion Btu in the High Dema nd Technology case and 56.2 quadrillion Btu in the Bes t Available Demand Technology case in comparison with the 2011 Demand Technology case. Electricity accoun ts for the largest share of the reductions in the High Demand Technology case (49 percent) and the Best Available Demand Technology case (51 percent). In addition to adopting more optimistic assumptions in the High Demand Technology and Best Available Demand Technology cases for end-use equipment, residential PV and wind technologies are assumed to have greater c ost declines than in the Reference case, contributing t o reductions in purchased electricity. In 2035, resid ential PV and wind systems produce 23 billion kilowatthour s more electricity in the Best Available Demand Technology case than in the 2011 Demand Technology case.
In the High Demand Technology and Best Available De mand Technology cases, energy use for residential s pace heating again shows the most improvement relative to the 20 11 Demand Technology case. Large kitchen and laundry appliances claim a small share of the reductions, as Federal s tandards limit increases in energy consumption for those uses even in the 2011 Demand Technology case. Light-emitting diodes (LED) lighting provide the potential for further sa vings in the High and Best Available Demand Technology cases beyond the r eductions realized as a result of the EISA2007 (Pub lic Law 110-140) lighting standards.



### Results for the commercial sector

figure data

Like the residential sector, analysis results for t he commercial sector are discussed here in terms of cumulative reductions relative to the 2011 Demand Technology case, in order to illustrate the effect of efficiency improvements over the period from 2011 t o 2035. Buildings in the commercial sector are less homogeneous than those in the residential sector, i n 

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commercial products are subject to Federal efficien cy standards, FEMP guidelines, and ENERGY STAR spec ifications, coverage is not as comprehensive as in the resident ial sector. Still, those initiatives and the ensuin g efficiency improvements contribute to a cumulative reduction in commercial delivered energy use of 4.1 quadrillion Btu in the Reference case relative to the 2011 Demand Technology case (Figure 22). Virtually all of the reduction is in purchased electri city. Increased adoption of DG and CHP accounts for 0.4 quadrillion Btu (115 billion kilowatthours) of the cumulative reduction in purchased electricity in the Reference case. Commercial natural gas use i s actually slightly higher in the Reference case because of the increased penetration of CHP. Office-related computer equipme nt sees the most significant end- use energy savings relative to the 2011 Demand Technology case, primarily because laptop co mputers gain market share from desktop computers.
Commercial heating, ventilation and cooling accountfor almost 50 percent of the 17.1 quadrillion Btu in cumulative energy savings in the High Demand Technology case relative to the 2011 Demand Technology case. The more optim istic assumptions for enduse equipment in the High Demand Technology case offset the additional energy consu med as a result of greater adoption of CHP, resulting in a cumulati ve reduction in natural gas consumption of 0.9 quad rillion Btu. The increase in distributed and CHP generation contribu tes 0.8 quadrillion Btu (231 billion kilowatthours) to the cumulative reduction in purchased electricity use.

Technologies such as LED lighting result in almost as much improvement as space heating and ventilatio n in the Best Available Demand Technology case relative to the 20 11 Demand Technology case. Significant reductions a re seen for all enduse services, with a cumulative reduction in ene rgy consumption of 24.6 quadrillion Btu. Even when consumers choose the most efficient type of each end-use technology, the more optimistic assumptions regarding technolo gy learning for advanced CHP technologies result in more natural ga s use in the Best Available Demand Technology case relative to the 2011 Demand Technology case.

In comparison to a case that restricts future equip ment to the efficiencies available in 2011, the alt ernative cases show the potential for reductions in energy consumption from the adoption of more energy-efficient technologies . In the Reference case, technology improvement reduces residential en ergy consumption by 12.3 quadrillion Btu—equivalentto 4.1 percent of total residential energy use—from 2011 to 2035 in c omparison with the 2011 Demand Technology case. In the commercial sector, energy consumption is reduced by 4.1 quadri llion Btu—equivalent to 1.7 percent of total commer cial energy use— over the same period. With greater technology impro vement in the High Demand Technology case, cumulati ve energy savings from 2011 to 2035 rise by an additional 6.4 percent and 5.5 percent in the residential and com mercial sectors, respectively. In the Best Available Demand Technolo gy case, the cumulative reductions in energy consum ption grow by an additional 8.2 percent and 3.1 percent in the resid ential and commercial sectors, respectively. In the Reference case, a cumulative total of 16.4 quadrillion Btu of energy consumption is avoided over the projection period r elative to the 2011 Demand Technology case. That reduction is roughly e quivalent to 80 percent of the energy that the buil dings sectors consumed in 2010. In the Best Available Demand Tech nology case, cumulative energy consumption is reduc ed by an additional 64.3 quadrillion Btu from 2011 to 2035.


## 4. Energy impacts of proposed CAFE standards for li ght-duty vehicles, model years 2017 to 2025 In response to environmental, economic, and energy security concerns, EPA and NHTSA in December 2011 j ointly issued a proposed rule covering GHG emissions and CAFE stand ards for passenger cars and light-duty trucks in MY2017 through MY 2025 [ 42 ]. EPA and NHTSA expect to announce a final rule in the second half of 2012. In this section, EIA uses the National Energy Modeling System (NEMS), which has b een updated since last year but, due to the timing of the modeling process, does not incorporate all information from the pending rulemaking process, to assess potential energy impacts of the regulatory proposal.
EPA is proposing GHG emissions standards that will reach a fleetwide LDV average of 163 grams CO 2 per mile (54.5 mpg equivalent) in MY 2025, or 49.6 mpg for the CAFE-on ly portion ( Table 8 ). Passenger car standards are made more stringent by reducing the average annual CO 2 emissions allowed by 5 percent per year from MY 20 16 through MY 2025. Average annual CO2 emissions from light-duty trucks are red uced by 3.5 percent per year from MY 2016 through M Y 2021, with 

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through MY 2025, light-duty trucks would be require d to achieve a 5-percent average annual reduction r ate. In this section, EIA assumes that the reductions in GHG emissions re quired under EPA standards exceed the reductions re quired under the NHTSA CAFE standards and are achieved through chang es other than those that would provide further impr ovement in fuel economy as tested for compliance with the NHTSA sta ndards.
NHTSA has proposed CAFE standards for LDVs that wil l reach a fleetwide average of 49.6 mpg in MY 2025, based on the projected inclusion of reductions in GHG emissions that are achieved by means other than improvements in fuel economy. CAFE standards are proposed for MY 2017 through MY 2021, and conditionally for MY 2022 through MY 2025 . The proposed standards for passenger cars increase by 4 .1 percent per year for MY 2017 through MY 2021 and 4.3 percent for MY 2022 through MY 2025. For light-duty trucks, the CAFE standards would increase by 2.9 percent per y ear for MY 2017 through MY 2021, with greater improvement required for smaller light-duty trucks and somewhat smaller improvement required for larger light-duty trucks. For MY 2022 through MY 2025, CAFE standards for all light-duty trucks would increase by 4.7 percent per year. Although there are complex dynamics in play among the CAFE standards and othe r policies, including those related to biofuels [ 43 ] and other gasoline alternatives, CAFE standards a re the single most powerful regulatory mechanism affecting energy use in the U. S. transportation sector.

AEO2012

includes a CAFE Standards case that incorporates t he proposed NHTSA fuel economy standards for MY 201 7 through MY 2025. Fuel economy and GHG emissions sta ndards for MY 2011 through MY 2016 have been promul gated already as final rules and are represented in the A EO2012 Reference case. Further, the Reference case assumes that CAFE standards rise slightly to meet the requirement tha t LDVs reach 35 mpg by 2020 mandated in EISA2007.

As modeled by EIA, compliance with the more stringe nt fuel economy standards in the CAFE Standards cas e leads to a change in the vehicle sales mix. Vehicles that use electric power stored in batteries, or use a combin ation of a liquid fuel (including gasoline) and electric power stored in b atteries for motive and/or accessory power—such as hybrid electric vehicles (HEVs) or plug-in hybrid electric vehicles (PHEVs)—or that use liquid fuels other than gasoli ne, such as diesel or E85, play a larger role than in the Reference case. The CAFE Standards case also projects a significan t improvement in the fuel economy of traditional vehicles with gasoline internal combustion engines with and without micro hybrid technologies. In the analysis, vehicles that combine gasoline intern al combustion engines with micro hybrid systems are p rojected to have the largest increase in sales relative to the Reference case (Figure 23 and Table 9 ).

figure data
Gasoline-only vehicles retain the single largest sh are of new vehicle sales in 2025. In order to meet increas ed fuel economy requirements, the average fuel economy of gasoline vehicles, including micro hybrids, is rais ed by the introduction of new fuelefficient technologies and improved vehicle designs. The fuel economy of gasol ineonly passenger cars, including micro hybrids, incre ases from 32 mpg in 2010 to 51 mpg in 2025 in the CAFE Standards case, compared with 38 mpg in 2025 in the Reference case. The fuel economy of gasoline-powere d light-duty trucks, including micro hybrids, rises s imilarly, from 24 mpg in 2010 to 37 mpg in 2025 in the CAFE Standards case, compared with 31 mpg in 2025 in the Reference case.

As vehicle attributes, such as horsepower and weigh t, 

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8/9/2012 http://www.eia.gov/forecasts/aeo/IF_all.cfmchange in response to the more stringent fuel econo my standards, some consumers switch from passenger cars to light

trucks. Light-duty trucks account for 39 percent ofnew LDV sales in 2025 in the CAFE Standards case, higher than their 37 percent share in 2025 in the Reference case but sti ll much lower than their 2005 share of more than 50 percent. In 2025, new passenger cars average 56 mpg and light-duty trucks average 40 mpg in the CAFE Standards case, compare d with 41 mpg and 31 mpg, respectively, in the Reference case. Al though more stringent standards stimulate sales of vehicles with higher fuel economy, it takes time for new vehicles to pen etrate the vehicle fleet in numbers that are suffic iently large to affect the average fuel economy of the entire U.S. LDV stock. Currently there are about 230 million LDVs on the r oad in the United States, projected to increase to 276 million in 203 5. As a consequence of the gradual scrapping of old er vehicles and the introduction of new, more fuel-efficient models, th e average on-road fuel economy of the LDV stock, re presenting the fuel economy realized by all vehicles in use, increases from around 20 mpg in 2010 to 22 mpg in 2016, 27.5 mpg in 2025, and 34.5 mpg in 2035, as compared with 28 mpg in 2035 i n the Reference case (Figure 24).

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More stringent fuel economy standards lead to reductions in total energy consumption. Total cumulative deliv ered energy consumption by LDVs from 2017 to 2035 is 8 percent lower in the CAFE Standards case than in th e Reference case. LDV delivered energy consumption is 6 percent lower in 2025 in the CAFE Standards case th an in the Reference case and 17 percent lower in 2035. Total consumption of petroleum and other liquids in the transportation sector is 0.5 million barrels per da y lower in 2025 and 1.4 million barrels per day lower in 20 35 in the CAFE Standards case than in the Reference case (Figure 25). The existing standards are modestly exceeded in the Reference case. If the standards are just met, the reduction in liquids consumption is 0.5 mi llion barrels per day in 2025 and 1.6 million barrels perday in 2035 in the CAFE Standards case relative to the Reference case. The reductions in total delivered energy use and li quid fuel consumption become more pronounced later in the projection, as more of the total vehicle stock consists of vehicle s with higher fuel economy.

figure data
The more stringent regulatory standards in the CAFE Standards case change the composition of the vehicl e fleet by fuel type and shift the mix of fuels consu med. Nevertheless, motor gasoline, including gasoline blended with up to 15 percent ethanol (used in vehicles manufactured in MY 2001 and after), remains the predominant fuel by far for LDVs in the CAFE Standa rds case, accounting for 84 percent of LDV delivered en ergy consumption in 2035—only slightly less than its 86- percent share in 2035 in the Reference case.

Total motor gasoline demand for LDVs is 19 percent lower in the CAFE Standards case in 2035 than in th e 

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reduces the amount of ethanol used in E10 and E15 g asoline blends. As a consequence, more E85 fuel is sold to meet the RFS. E85 accounts for 10 percent of delivered energ y consumption by LDVs in 2035, compared with 8 perc ent in the Reference case. Diesel fuel accounts for 5 percent of LDV delivered energy consumption in 2035, simila r to its share in the Reference case. Electricity use by LDVs grows in th e CAFE Standards case but still makes up less than 1 percent of LDV delivered energy demand in 2035.

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Reductions in LDV delivered energy consumption redu ce GHG emissions from the transportation sector. From 2017 and 2035, cumulative CO 2 emissions from transportation are 357 million metric tons (mmt) lo wer in the CAFE Standards case compared to the Reference case, a reduction of 5 percent. Transportation GHG emissions decline from 1,876 mmt in 2010 to 1,759 m mt in 2025 and to 1,690 mmt in 2035, reductions of 4 percent and 10 percent from the Reference case, respectively (Figure 26).


## 5. Impacts of a breakthrough in battery vehicle technology The transportation sector's dependence on petroleum

based fuels has prompted significant efforts to dev elop technology and alternative fuel options that addres s associated economic, environmental, and energy se curity concerns. Electric drivetrain vehicles, including HEVs, PHEVs , and plug-in electric vehicles (EVs), are particul arly well suited to meet those objectives, because they reduce petroleum consumption by improving vehicle fuel economy and, in the case of PHEVs and EVs, substitute electric power for gasoline use (see Table 10 for a descriptive list of electric drivetrain tech nologies).

AEO2012

includes a High Technology Battery case that exami nes the potential impacts of significant breakthrou ghs in battery electric vehicle technology on vehicle sale s, energy demand, and CO2 emissions. Breakthroughs may include a dramatic reduction in the cost of battery and nonba ttery systems, success in addressing overheating an d life-cycle concerns, as well as the introduction of battery-powered elec tric vehicles in several additional vehicle size cl asses. A brief summary of the results of the High Technology Battery case fol lows a discussion of the current market for batteryelectric vehicles.
Sales of light-duty HEVs, introduced in the United States more than a decade ago, peaked at about 350, 000 new sales in 2007 and have maintained a roughly 3-percent share of total LDV sales through 2011. PHEVs were introdu ced in the United States at the end of 2010 with the production of th e Chevy Volt, a PHEV-40 (PHEV with a 40-mile range) . Although manufacturer plans call for increased production ofPHEVs, sales in the first full year were under 10, 000 units [ 44 ]. EVs were first introduced in the early 1900s, and manufactur ers again made EVs available in the 1990s but with a focus on niche markets. The Nissan Leaf, an EV-100 (EV with a 100- mile range) introduced around the same time as the Chevy Volt, has sparked interest in the wider commercial prospects for EVs; however, sales in 2011 remained below 10,0 00 units.

The individual decision to purchase a vehicle is in fluenced by many factors, including style, performa nce, comfort, environmental values, expected use, refueling capab ility, and expectations of future fuel prices. In g eneral, one of the single most important factors consumers consider when deci ding to purchase a vehicle is cost. Specifically, they generally are more willing to purchase new vehicle technologies, such as battery electric systems, instead of conventional gasoline internal combustion engines (ICEs) if the economic benefit o ver a period of ownership is greater than the initi al price of the vehicle. Additional costs and benefits—such as refueling tim e or difficulty of refueling, increased or decrease d maintenance, and 

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a vehicle, even if it accrues fuel cost savings bey ond the initial cost over a relatively short period, because they are unfamiliar with the new technology or alternative fuel.

Battery electric vehicles offer an economic benefitto consumers over conventional gasoline ICEs in te rms of significant fuel cost savings from both increased fuel economy for H EVs and PHEVs and the displacement of gasoline with electricity for PHEVs and EVs. Currently available battery electricvehicles such as the Toyota Prius (HEV), Chevy Vol t (PHEV), and Nissan Leaf (EV) achieve much higher fuel economy ( mpg) and, with the higher efficiency of electric mo tors, higher gasolineequivalent mpg in electric mode, providing consumer s with lower fueling costs. The Toyota Prius achiev es an EPA- estimated 39 to 53 mpg, depending on trim and driving test cy cle. The Chevy Volt achieves 35 to 40 mpg in charge -sustaining mode [ 45 ] and 93 to 95 mpg equivalent in charge-depleting m ode. The Nissan Leaf achieves 99 mpg equivalent. In comparison, the Toyota Corolla, a passenger car generally simil ar to the Prius, achieves 26 to 34 mpg; the Chevy C ruze, a passenger car in the compact car size class similar to the Volt, achieves 25 to 42 mpg; and the Nissan Versa, a subc ompact passenger car similar to the Leaf [ 46 ], achieves 24 to 34 mpg.

The inclusion of advanced battery technology that i ncreases fuel economy and, in the case of PHEVs and EVs, displaces gasoline with electricity increases the initial cos t of the vehicle to the consumer. The Toyota Prius has a manufacturer's suggested retail price (MSRP) between $24,000 and $ 29,500 (compared with $16,130 to $17,990 for the Toyota Corolla); the Chevy Volt has an MSRP between $39,145 and $42,085 (compared with $16,800 to $23,190 for the Chevy Cru ze); and the Nissan Leaf has an MSRP between $35,200 and $37,250 (compared with $14,480 to $18,490 for the Nissan V ersa) [ 47 ]. Based on these MSRPs, the current incremental consu mer purchase cost of a battery electric vehicle rel ative to a comparable conventional gasoline vehicle is around $7,000 for an HEV and $20,000 for a PHEV or EV, bef ore accounting for Federal and State tax incentives.

Although consumers may value high-cost battery elec tric vehicles for a variety of reasons, it is unlik ely that they can achieve wide -scale market penetration while their additional pu rchase costs remain significantly higher than the p resent value of future fuel savings. Currently, the discounted fuel savings achieved, assuming five years of ownership with future fuel savings discounted at 7 percent, are significantly less than the incremental purchase cost of the vehi cles ( Table 11 ). This result is true even if gasoline is $6.00 per gallon . This calculation does not take into account any d ifference in maintenance cost or refueling infrastructure.

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Recognizing the potential of HEVs, PHEVs, and EVs t o reduce U.S. petroleum consumption and save consumers refueling costs, efforts are underway at both the p ublic and private levels to address several of the barrie rs to wide-scale adoption ofbattery electric vehicle technology. Paramount among the barriers are reducing the cost of battery electric vehicles by lowering battery and nonbattery system costs and solving battery life-cy cle and overheating limitations that will allow batterystorage to downsize while maintaining a given driving range . For example, battery and nonbattery systems costs could be reduced by improving the manufacturing process, changing battery chemistry, or improving the electr ic motor. Solving battery life-cycle and overheating concerns would allow battery capacity to be downsiz ed, which would improve the depth of discharge and make the battery less expensive. In addition, public and private efforts to address other obstacles to wide r adoption of plug-in 

## Page 16of 55 U.S. Energy Information Administration (EIA)

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8/9/2012 http://www.eia.gov/forecasts/aeo/IF_all.cfmbattery vehicles are underway, including the develo pment of public charging infrastructure.

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The AEO2012

High Technology Battery case examines the potential impacts ofbattery technology breakthroughs by assuming the attainment of program goals established by DOE's Office of Energy Efficiency and Renewable Energy (EERE) for high-energy battery storage cost, maximum depth of discharge, and cost of a nonbattery traction drive system for 2015 and 2030 (Figures 27 and 28) [ 48 ]. EERE's program goals represent significant breakthroughs in battery and nonbattery systems, in terms of costs and life-cycle and safety concerns, in comparison with current electric vehicle technologi es. Further, with breakthroughs in battery electric veh icle technology, more vehicle size classes are assumed t o be available for passenger cars and light-duty trucks.

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Reduced costs for battery and nonbattery systems in the High Technology Battery case lead to significantly lower HEV, PHEV, and EV costs to the consumer (Figures 29 and 30). The Reference case already projects a much lower real price to consumers for battery electric vehicles in 2035 relative to 2010 as a result of cost reduct ions for battery and nonbattery systems. Those declines are furthered in the High Technology Battery case. The prices of HEVs and PHEVs with a 10-mile range decli ne by an additional $1,500, or 5 percent, in 2035 in t he High Technology Battery case relative to the Reference c ase. For PHEVs with a 40-mile range the relative decline is $3,500, or 11 percent, in 2035. For EVs with 100-mi le (EV100) and 200-mile (EV200) ranges the relative declines are $3,600 and $13,300, or 13 percent and 30 percent, respectively, in 2035 relative to the Refe rence
case.

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Lowervehicle prices lead to greater penetration of batt ery electric vehicle sales in the High Technology Battery case than projected in the Reference case. Battery elect ric vehicles, excluding mild hybrids, grow from 3 perce nt of new LDV sales in 2013 to 24 percent in 2035, compar ed with 8 percent in 2035 in the Reference case (Figur e 31). 

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8/9/2012 http://www.eia.gov/forecasts/aeo/IF_all.cfmDue to the still prohibitive incremental cost, EV20 0

vehicles do not achieve noticeable market penetrati on.

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Plug-in vehicles, including both PHEVs and EVs, sho w the largest growth in sales in the High Technology Battery case, resulting from the relatively larger incremental reduction in vehicle costs. Plug-in veh icle sales grow to just over 13 percent of new vehicle s ales in 2035, compared with 3 percent in 2035 in the Refere nce case, with EV sales growing to 8 percent of new LDV sales in 2035, compared with 2 percent in 2035 in t he Reference case. Virtually all sales of plug-in vehi cles are EVs with a 100-mile range, given the prohibitive co st, even in 2035, of batteries for EVs with a 200-mile range. PHEVs grow to just under 6 percent of total sales, compared with 2 percent in 2035 in the Reference ca se. Most PHEV sales are vehicles with a 10-mile all-ele ctric range.
Although plug-in vehicle sales increase substantial ly in the High Technology Battery case, that growth is tempered by the lack of widespread high-speed recharging infrastruc ture. In the absence of such public infrastructure, consumers must rely almost entirely on recharging at home. According to data from the 2009 Residential Energy Consumption Survey, 49 percent of households that own vehicles park within 20 feetof an electrical outlet [ 49 ]. A widespread publicly available infrastructure was not considered as part of the High Technology Battery case, which limits the maximum market pote ntial of PHEVs and EVs.
HEV sales, including an ICE powered by either diese l fuel or gasoline, increase in the High TechnologyBattery case from 3 percent of sales in 2013 to 11 percent in 2035, com pared with 5 percent in 2035 in the Reference case. Although the cost declines for HEVs are modest relative to those for otherbattery electric vehicle types, HEVs benefit from being unconstrained by the lack of recharging infrastructure.

Increased sales of battery electric vehicles in the High Technology Battery case lead to their gradual penetration throughout the LDV fleet. In 2035, HEVs represent 9 percent ofthe 276 million LDV stock, as compared with 4 perc ent in the Reference case. EVs and PHEVs each account for about 5 percen t of the LDV stock in the High Technology Battery c ase in 2035, compared with 1 percent each in the Reference case.

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The penetration of battery electric vehicles with r elatively higher fuel economy and efficient electric motors reduces total energy use by LDVs from 15.6 quadrillion Btu in 2013 to 14.8 quadrillion Btu in 2035 in the High Technology Battery case, compared with 15.5 quadril lion Btu in 2035 in the Reference case (Figure 32). LDV liquid fuel use declines to 14.6 quadrillion Btu in 2035 i n the High Technology Battery case, and their electricityuse increases to 0.2 quadrillion Btu—as compared with 1 5.4 

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8/9/2012 http://www.eia.gov/forecasts/aeo/IF_all.cfmquadrillion Btu of liquid fuel consumption and esse ntially

no electricity consumption in 2035 in the Reference case. The reduction in liquid fuel consumption in the High Technology Battery case lowers U.S. net imports of petroleum f rom 8.5 million barrels per day in 2013 to 6.9 mill ion barrels per day in 2035, compared with 7.2 million barrels per day in 2035 in the Reference case.

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The reduction in total energy consumption by LDVs a nd displacement of petroleum and other liquid fuels wi th electricity decreases LDV energy-related CO 2 -equivalent emissions from 1,030 million metric tons in 2013 to 935 million metric tons in 2035 in the High Technology Battery case, which represents a 2-percent decrease from 95 8 million metric tons in 2035 in the Reference case ( Figure 33). CO 2 and other GHG emissions from the electric power consumed by PHEVs and EVs is treated as representative of the national electricity grid and not regionalized. Ultimately, the CO 2 and other GHG emissions of plug- in vehicles will depend on the fuel used in generating electricity.

The High Technology Battery case assumes a breakthrough in the costs of batteries and nonbatte ry systems for battery electric vehicles. Yet, despite the assumed dramatic decline in battery and nonbat tery system costs, battery electric vehicles still face obstacles to w ide-scale market penetration.

First, prices for battery electric vehicles remain above those for conventional gasoline counterparts, even with the assumption of technology breakthroughs throughout the projecti on period. The decline in sales prices relative to those for conventional vehicles may be enough to justify purchases by cons umers who drive more frequently, consider relativel y longer payback periods, or would purchase a more expensive but env ironmentally cleaner vehicle for a moderate additio nal cost. However, relatively more expensive battery electric vehicles may not pay back the higherpurchase cost over the ownership period for a significant population of consumers.

In addition, EVs face the added constraint of plug- in infrastructure availability. Currently, there ar e about 8,000 public locations in the United States with at least one ou tlet for vehicle recharging, about 2,000 of which a re in California [ 50 ]. In comparison, there are some 150,000 gasoline refueli ng stations available for public use. Without the c onstruction of a much larger recharging network, consumers will have to r ely on residential recharging, which is available f or only around 40 percent of U.S. dwellings.

Further, recharging times differ dramatically depen ding on the voltage of the outlet. Typical 120-volt outlets can take up to 20 hours for a full EV battery to recharge; a 240-volt outlet can reduce the recharging time to about 7 h ours [ 51 ]. Quickrecharging 480-volt outlets are under consideration for 30-minute "ultra-quick" recharges, but they ma y raise concerns related to safety and residential or commercial bui lding codes. Even with ultra-quick recharging, EVs still would require substantially longer times for refueling than are r equired for ICE vehicles using liquid fuels. Given the concerns about availability and duration of recharging, the obstac le of severe range limitation, which does not affect PHEVs or HEVs, may inhibit the adoption of EVs by consumers.

Finally, another obstacle to wide-scale adoption ofbattery electric vehicles and other types of alter native-fuel vehicles is the increase in fuel economy for conventional gasoline vehicles and other types of AFVs resulting from hig her fuel economy standards for LDVs. Final standards for LDV fuel ec onomy currently are in place through MY 2016, and n ew CAFE standards 

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8/9/2012 http://www.eia.gov/forecasts/aeo/IF_all.cfmproposed for MY 2017 through MY 2025 would increase combined LDV fuel economy to 49.6 mpg (56.0 mpg fo r passenger

cars and 40.3 mpg for light-duty trucks) [ 52 ]. While the standards themselves may promote the a doption of battery electric vehicles, they also could considerably change the e conomic payback of electric drivetrain vehicles by decreasing consumer refueling costs for conventional vehicles, thus low ering the fuel savings of electric drivetrain vehic les and making the upfront incremental cost more prohibitive. The potential im pact of CAFE standards on other vehicle attributes, costs, and fuel savings adds to the complexity of this dynamic.


## 6. Heavy-duty natural gas vehicles Environmental and energy security concerns, togethe r with recent optimism about natural gas supply and recent lower natural gas prices, have led to significant interes t in the potential for fueling heavy-duty vehicles (HDVs) with natural gas produced domestically. Key market uncertainties wit h regard to natural gas as a fuel for HDVs include fuel and infrastructure issues (such as the build-out process for refueling stations and whether there will be sufficient dema nd for refueling to cover the required capital outlays, and retail pricing an d taxes for liquefied natural gas [LNG] and compres sed natural gas [CNG] fuels); and vehicle issues (including incremental c osts for HDVs fueled by natural gas, availability o f fueling infrastructure, cost-effectiveness in view of average vehicle usage , vehicle residual value, vehicle weight, and vehic le refueling time).



### Current state of the market At present, HDVs in the United States are fueled al most exclusively by petroleum-based diesel fuel [ 53 ]. In 2010, use of petroleum-based diesel fuel by HDVs accounted for 1 7 percent (2.2 million barrels per day) of total pe troleum consumption in the transportation sector (12.8 million barrels perday) and 12 percent of the U.S. total for all sect ors (18.3 million barrels per day). Consumption of petroleum-based diesel fuel byHDVs increases to 2.3 million barrels per day in 2 035 in the AEO2012 Reference case, accounting for 19 percent of total petroleum consumption in the transportation sector (12.1 million barrels per day) and 14 percent of the U.S. total for all s ectors (17.2 million barrels per day).

Historically, natural gas has played a negligible r ole as a highway transportation fuel in the United States. In 2010, there were fewer than 40,000 total natural gas HDVs on the roa d, or 0.4 percent of the total HDV stock of nearly 9 million vehicle s. Sales of new HDVs fueled by natural gas peaked at about 8 ,000 in 2003, and fewer than 1,000 were sold in 201 0 out of a total of more 360,000 HDVs sold. With relatively few vehicle s on the road, natural gas accounted for 0.3 percent oftotal energy used by HDVs in 2010.
As of May 2012, there were 1,047 CNG fueling statio ns and 53 LNG fueling stations in the United States , with 53 percent of the CNG stations and 57 percent of the LNG stations being privately owned and not open to the public [ 54 ]. Further, the stations were not evenly distributed across the Uni ted States, with 22 percent (227) of the CNG statio ns and 68 percent (36) of the LNG stations located in California. In compa rison, nationwide, there were more than 157,000 sta tions selling motor gasoline in 2010 [ 55 ].

figure data

Developments in natural gas and petroleum markets i n recent years have led to significant price disparit ies between the two fuels and sparked renewed interest in natural gas as a transportation fuel. Led by techno logical breakthroughs in the production of natural gas from shale formations, domestic production of dry natural gas increased by about 14 percent from 2008 to 2011. In the AEO2012

Reference case, U.S. natural gas production (including supplemental gas) increases from 21.6 tr illion cubic feet in 2010 to 28.0 trillion cubic feet in 2 035. Further, although the world market for oil and petr oleum 

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8/9/2012 http://www.eia.gov/forecasts/aeo/IF_all.cfmproducts is highly integrated, with prices set in t he global

marketplace, natural gas markets are less integrate d, with significant price differences across region s of the world. With the recent growth in U.S. natural gas production, domes tic natural gas prices in 2012 are significantly lo wer than crude oil prices on an energy-equivalent basis (Figure 34).



### Fuel and infrastructure issues Even when it appears that an emerging technology ca n be profitable with significant market penetration , achieving significant penetration can be difficult and, potentially, unat tainable. Refueling stations for NGVs are unlikely to be built without some assurance that there will be sufficient numbers of NGVs to be refueled, soon enough to allow for recov ery of the capital investment within a reasonable period of time. In t erms of estimating the prices that will be charged for NGV fuels beyond the cost of the dry natural gas itself, and the issue o f expected utilization rates, there are additional uncertainties related to capital and operating costs, taxes, and the potenti al of prices being set on the basis of the prices o f competing fuels.



### Basic fuel issues Diesel fuel falls into the category of distillate f uels, which have constituted more than 25 percent o f U.S. refinery output in recent years. The cost of diesel fuel is linked clo sely to the value of crude oil inputs for the refin ing process. In 2011, the spot price of Gulf Coast ultra-low sulfur diesel fuel av eraged $2.97 per gallon. The wholesale diesel price reflects crude oil costs, as well as the difference between the wholesale pri ce at the refinery gate and the cost of crude oil i nput, commonly referred to as the "crack spread," which reflects the costs and profits of refineries.

Beyond the wholesale price, the pump price of diese l fuel reflects distribution costs, Federal, State, and local fuel taxes, retailing costs, and profits. For diesel fuel, with an average energy content of 138,690 Btu per gallo n, the 2011 national average retail price of $3.84 per gallon is equival ent to about $27.80 per million Btu.

Although early models of NGVs sometimes were less f uel-efficient than comparable diesel-fueled vehicle s, current technologies allow for natural gas to be used as ef ficiently as diesel in HDV applications. Therefore, comparisons between natural gas and diesel fueling costs can be based o n the price of energy-equivalent volumes of fuel. F or this analysis, the cost and price of natural gas fuels are expressed i n terms of diesel gallon equivalent (dge). For exam ple, with an energy content of approximately 84,820 Btu per gallon, 1 g allon of LNG is equivalent in energy terms to 0.612 gallons of diesel fuel.
Fuel costs for LNG and CNG vehicles depend on the c ost of natural gas used to produce the fuels, the c ost of the liquefaction or compression process (including prof its), the cost of moving fuel from production to re fueling sites (if applicable), taxes, and retailing costs. Costs can vary with the scale of operations, but the signific ant disparity between current natural gas and crude oil prices suggests t hat the cost of CNG and LNG fuels in dge terms coul d be significantly below the price of diesel fuel.

There are different wholesale natural gas prices an d capital costs associated with CNG and LNG station s. CNG retail stations, which typically have connections to the p ipeline distribution network and thus require compr ession equipment and special refueling pumps, are likely to pay prices f or natural gas that are similar to those paid by co mmercial facilities. For LNG stations, insulated LNG storage tanks and speci al refueling pumps are needed. LNG typically would be delivered from a liquefaction facility that, depending on its scale, would pay a natural gas price similar to the price s paid by electric power plants. The costs of liquefying and transporting th e fuel to the retail station would ultimately be in cluded in the retail price.

In a competitive market, retail fuel prices should reflect costs, including input, processing, distrib ution, and retailing costs, normal profit margins for processors, distributors, and retailers, and taxes. For example, the market for diesel fuel, which is produced by a large number of foreign and domestic refiners and is sold through numerous distributors and retail outlets, generally is considered to be a competitive market, in which retail prices follow costs.
CNG and LNG markets, at least in their initial stag es, may not be as competitive as diesel fuel market s. For example, at public refueling stations, LNG and CNG currently se ll at prices significantly higher than would be sug gested by a long-term analysis of cost-based pricing. According to DOE's April 2012 "Clean Cities Alternative Fuel Price Rep ort," the average 

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8/9/2012 http://www.eia.gov/forecasts/aeo/IF_all.cfmnationwide nominal retail price for LNG was $3.05 p er dge, and the average for CNG was $2.32 per dge [ 56 ].

If the use of LNG and/or CNG to fuel HDVs starts to grow, it is likely to take some time before fuel p roduction and refueling infrastructure become sufficiently widespread for c ompetition among fuel providers alone to assure tha t fuel prices are more closely linked to cost-based levels. However, even without many fuel providers, operators of an LNG an d/or CNG vehicle fleet may be in a position to negotiate cost-based fuel prices with refueling station operators seekin g to lock in demand for their initial investments in refueling infrastructu re. Such arrangements provide an alternative to rel iance on centrally fueled fleets as a means of circumventing the problem of h ow to introduce NGVs and natural gas refueling infr astructures concurrently.



### Build-out process for refueling stations It is not clear how NGVs and an expanded natural ga s refueling infrastructure ultimately will evolve. One view is that a "huband-spoke" model for refueling infrastructure will expand sufficiently in multiple areas for a point-t o-point system to take hold eventually. The "hubs" in the model would include t he local refueling infrastructure, currently in pla ce primarily to support local fleets. The "spokes" would ensure that refuel ing infrastructure is in place on the main transportation corridors connecting the hubs.
Several regional efforts are in place to encourage such "hub-and-spoke" growth for NGV refueling facil ities. They include the Texas Clean Transportation Triangle [ 57 ], a strategic plan for CNG and LNG refueling stati ons between Dallas, San Antonio, and Houston; and the Interstate Clean Transportatio n Corridor [ 58 ], which aims to provide LNG fueling stations between such major western cities as Los Angeles, Las Vegas, Pho enix, Reno, Salt Lake City, and San Francisco. Ther e also is a plan for a Pennsylvania Clean Transportation Corridor [ 59 ], which would provide CNG and LNG fueling stations between Pittsburgh, Harrisburg, Scranton, and Philadelphia.

In several corridors, Federal and State incentives are subsidizing both the construction of refueling stations and the production of heavy-duty LNG vehicles [ 60 ], in an effort to ensure that both demand and supp ly will be in place concurrently. A major question is whether gaps between isolated t argeted markets can be bridged to provide a nationw ide refueling structure that will allow heavy-duty NGVs to travel almost anywhere.



### Sufficiency of demand for refueling to cover capital outlay The cost of providing refueling services for NGVs d epends on a number of factors and is distinctly different for CNG and LNG vehicles. Investment decisions are likely to be bas ed on levels of demand. NGV refueling capability ca n be added at an existing facility or at a separate dedicated facili ty (which would require an additional investment). The costs depend in part on the number of fueling hoses added. LNG stations in particular benefit from higher volumes, but they al so require significant additional land to accommodate storage tank(s), and they must satisfy special safety requirements — both of which add costs that can vary significantly from place to place. On e added cost in operating an LNG station is the nee d for safety suits and specialized training for station attendants who dis pense the fuel.
LNG typically is delivered to refueling stations vi a tanker truck from a separate liquefaction facilit y, the proximity of which is a major factor in the cost and frequency of deliverie s. Any significant expansion of LNG refueling capac ity also will require expanded liquefaction capacity, which currently is not sufficiently dispersed throughout the country t o support a nationwide LNG refueling infrastructure. Although there are se veral dedicated large-scale natural gas liquefactio n facilities in the United States, primarily in the West, there are smaller li quefaction plants and LNG storage tanks currently i n use for meeting peakshaving needs of utilities and pipelines during times of high demand. There are more than 100 such facilities in the United States, with a combined liquefaction capacit y of more than 6 billion cubic feet per day. The majority are concentrated in the Northeast and Southeast [ 61 ].



### Retail prices and taxes for LNG and CNG fuels Even if the costs are fully known, retail prices fo r CNG and LNG transportation fuels remain uncertain , given questions about whetherdispensers would charge higher prices in order to recover costs more rapidly if the facility were und erutilized or 

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8/9/2012 http://www.eia.gov/forecasts/aeo/IF_all.cfmwould set prices to be competitive with the price of diesel. Prices charged at private station s for fleet vehicles presumably

would be based on cost. With the number of refuelin g stations limited, competition between retailers is likely t o be limited, at least initially. However, NGV refueling stations pr esumably would want to provide sufficient economic incentive in terms of the competitiveness of fuel prices to encourage mor e purchases of NGVs. NGV fuel is taxed at State and Federal levels. Currently, on a Federal level, CNG is taxed at the same rate as gasoline on an energy-equivalent basis ($0.18 per gasoline gallon equivalent, or $0.21 per dge). However, LNG is taxed at a higher effective rate than diesel fue l, because it is taxed volumetrically at $0.24 per LNG gallon equivalent ( $0.40 per dge) rather than on the basis of energy c ontent [ 62 ]. State taxes vary, averaging $0.15 per dge for CNG and $0.24 perdge for LNG.



### Vehicle Issues

Incremental vehicle cost NGVs have significant incremental costs relative to their diesel-powered counterparts because of the n eed for pressurization and insulation of CNG or LNG tanks and the lower en ergy content of natural gas as a fuel. Total increm ental costs relative to diesel HDVs range from about $9,750 to $36,000 for Class 3 trucks (GVWR 10,001 to 14,000 pounds), $34, 150 to $69,250 for Class 4 to 6 trucks (GVWR 14,001 to 26,000 poun ds), and $49,000 to $86,125 for Class 7 and 8 truck s (GVWR greater than 26,001 pounds). The incremental costs of heavy -duty NGVs depend in large part on the volume of th e vehicle's CNG or LNG storage tank, which can be sized to match its t ypical daily driving range. Non-storage-tank increm ental costs average about $2,000 for Class 3 vehicles, $20,000 for Clas s 4 to 6 vehicles, and $30,000 for Class 7 to 8 veh icles [ 63 ]. Fuel storage costs are about $350 per gallon diesel equivalent f or CNG, with the incremental cost for Class 3 CNG v ehicle storage tanks ranging between about $8,000 and $30,000; and about$475 per gallon diesel equivalent for LNG, with th e incremental cost for Class 4 to 8 LNG vehicle storage tanks ranging between about $14,000 and $52,000. Natural gas fuel storage technology is relatively mature, leaving only modest opportuni ty for cost reductions.



### Availability of fueling infrastructure The absence of widespread public refueling infrastr ucture can impose a serious constraint on heavy-dut y NGV purchases. Owners who typically refuel vehicles at a private c entral location do not face an absolute constraint based on infrastructure, however, and heavy-duty NGVs currently in operation have tended to be purchased by fleet operators who refuel consistently at a specific central location or in areas where th eir vehicles routinely operate on dedicated routes.



### Cost-effectiveness with average vehicle usage In order to take advantage of potential fuel cost s avings from switching to NGVs, owners must operate the vehicles enough to pay back the higher incremental cost in a reason able period of time. The payback period varies with miles driven and is shorter for trucks that are used more intensively. Payback periods for the upfront incremental costs o f NGVs are greater than 5 years for Class 3 vehicles unless they are driven at least 20,000 to 40,000 miles per year, and for Class 7 and 8 vehicles unless they are driven at least 60,000 to 80,000 mi les per year. Shorter payback periods, 3 years or l ess, may reflect typical owner expectations more accurately [ 64 ], but they require much more intensive use: around 60,000 to 80,000 miles annually for Class 3 vehicles and more than 100,000 miles an nually for Class 7 and 8 vehicles. For example, fora Class 7 or 8 compression ignition NGV with average fuel economy of 6 miles per gallon (which has a similar fuel eco nomy compared to a diesel counterpart) and an incremental cost of $80, 000, the payback period would be just over 3 years if the vehicle were driven 100,000 miles per year, assuming a diesel fu el price of $4.00 per gallon and an LNG fuel price of $2.50 per gallon. If the same Class 7 or 8 vehicle were driven 40,000 mi les per year, the payback period would be about 8 y ears. Further, without a widely available infrastructure, heavy -duty NGVs tend to be considered by centrally refueled fleets, which mayhave less mileage-intensive vehicle use.

figure data

According to the Department of Transportation's Veh icle Inventory and Use Survey [ 65 ], last completed in 2002, a 

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8/9/2012 http://www.eia.gov/forecasts/aeo/IF_all.cfmlarge segment of the HDV market simply does not dri ve

enough to justify the purchase of an NGV (Figure 35 ). Around 30 percent of Class 3 vehicles and 75 percent of Class 7 and 8 vehicles are not driven enough to reach the 5-year payback threshold mentioned above. This is a signif icant portion of the market that would require either more favorable fue l economics or lower vehicle costs before the purch ase of an NGV could be justified.



### Other market uncertainties Other factors may also affect market acceptance of heavy-duty NGVs. First, the purchase decision could be affected by the considerable additional weight of CNG or LNG tanks. For owners who typically "weight-out" a vehicle (d riving with a full payload), adding heavy CNG or LNG tanks necessitate s a reduction in freight payload. The EPA and NHTSA have estimated that about onethird of Class 8 sleeper tractors rou tinely are "weighted-out" [ 66 ].

A diesel tractor with 200 gallons of tank capacity and a fuel economy of 6 miles per gallon can drive 1,200 miles on a single refueling. The same tractor would need up to 110 dg e of LNG tank capacity, at a considerable weight pe nalty and an incremental cost of more than $80,000, to allow fora range of about 650 miles on a single refueling. Because owner/operators typically stop several times per da y, the reduction in unrefueled maximum range would not require additio nal breaks for vehicles with large CNG or LNG tanks. Ho wever, CNG and LNG vehicles that do not opt for lar ge tanks because of either weight or incremental cost considerations might have to refuel more frequently.

Finally, the owner perception of the balance of ris k and reward for large capital investment is an unc ertainty. Higher upfront capital costs can prove economically prohibitive fo r some potential owners. Even if the payback period for an investment in natural gas vehicles seemed acceptable, financing c onstraints or returns available on competing invest ment options could preclude the purchase. Additionally, the residual v alue of natural gas HDVs could, in theory, affect m arket uptake. With little natural gas refueling infrastructure in existence, the potential resale market is constrained to owner s of centrally operated fleets. However, lease terms tend to limit the impo rtance of this factor.

The complex set of factors influencing the potentia l for natural gas as a fuel for HDVs includes sever al areas for which policy mechanisms have been discussed. Most policy debates to date have considered the possibility of subsidi es to reduce the incremental cost of natural gas vehicles (for examp le, in Senate and House versions of the NewAlternative Transportation to Give Americans Solutions Act [ 67 ]) and Federal grant-based or other financial suppo rt for fueling station infrastructure. In addition, market hurdles related to consumer accept ance or payback periods might also be addressed thr ough loan guarantees or related financial support policies, b oth for the vehicles and for the refueling infrastr ucture.



### HD NGV Potential case results The AEO2012

HD NGV Potential case examines issues associated w ith expanded use of heavy-duty NGVs, under an assumption that the refueling infrastructure exists to support such an expansion. The HD NGV Potential case differs from an earlier sensitivity case completed as part of the Annual Energy Outlook 2010 , which focused on possible subsidies to expand the market potential for heavy-duty NGVs and limite d its attention to vehicles operating within 200 mi les of a central CNG refueling facility.

The AEO2012

HD NGV Potential case permits expansion of the HDVmarket to allow a gradual increase in the share ofHDV owners who would consider purchasing an NGV if just ified by the fuel economics over a payback distribu tion with a weighted average of 3 years. The gradual increase in the max imum natural gas market share reflects the fact tha t a national natural gas refueling program would require time to build o ut. The natural gas refueling infrastructure is exp anded in the HD NGV Potential case simply by assumption; it is not clea r how (or whether) specific barriers to natural gas refueling infrastructure investment can be overcome.

Incremental costs for NGVs in the HD NGV Potential case differ from those in the Reference case. In th e HD NGV Potential case, incremental costs are determined by assuming a set cost for CNG or LNG engines plus a CNG orLNG tank cost based on the average amount of daily travel and vehicle s ize class. The HD NGV Potential case includes separ ate delivered CNG and LNG fuel prices for fleet and nonfleet operator s. Added per-unit charges to recover infrastructure are set and held 

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a sufficiently high rate to warrant the capital inv estment, and that the prices charged for the fuel w ould be cost-based (i.e., station operators would not set prices on the basis of prices for competing fuels). Motor fuels taxes are assumed to remain at their current levels in nominal terms, maintaining the higher energy-equivalent tax on LNG relative to diesel fuel.

figure data
In defining CNG and LNG prices for the HD NGV Potential case, EIA examined current motor fuel tax es and any charges added to the commodity price of dry natural gas sold at private central refueling stati ons (fleets) and at retail stations where actual data w ere available. Accordingly, an HDV Reference case was developed from the AEO2012 Reference case, by including the updated fleet and retail CNG and LNG prices, to provide a consistent basis for compariso n with the HD NGV Potential case (Figure 36). The HDV Reference case assumes that Class 3 through 6 vehic les use CNG, obtained from either fleet operators (usin g fleet prices) or nonfleet operators (using retail prices) , and that Class 7 and 8 vehicles, both fleet and nonfleet, us e LNG.

figure data
Sales of heavy-duty NGVs rise dramatically in the H D NGV Potential case, based on the national availabil ity of refueling infrastructure and expanded market potent ial (Figure 37). Sales of new heavy-duty NGVs increase from 860 in 2010 (0.2 percent of total new HDV sale s) to about 275,000 in 2035 (34 percent of total new vehi cle sales), as compared with 26,000 in the HDV Referenc e case (3 percent of total new HDV sales). New heavy- duty NGVs gradually claim a more significant share of th e vehicle stock, from 0.4 percent in 2010 to 21.8 per cent (2,750,000 vehicles) in 2035, as compared with 2.4 percent (300,000 vehicles) in 2035 in the HDV Refer ence
case.

figure data

As a result of the large projected increase in sales of new heavy- duty NGVs, natural gas demand in the HDV sector rises from about 0.01 trillion cubic feet in 2010 t o 1.8 trillion cubic feet in 2035 in the HD NGV Potential case, as compared with 0.1 trillion cubic feet in the HDV Reference case (Figure 38). The natural gas share o f total energy use by HDVs grows from 0.2 percent in 2010 to 32 percent in 2035 in the HD NGV Potential case, 

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8/9/2012 http://www.eia.gov/forecasts/aeo/IF_all.cfmcompared with 1.6 percent in the HDV Reference case

.

Roughly speaking, about 1 trillion cubic feet of na tural gas consumed per year replaces 0.5 million ba rrels per day of petroleum and other liquids. Thus, natural gas cons umption by HDVs in the HD NGV Potential case displa ces about 850,000 barrels per day of petroleum and other liquids cons umption in 2035 (Figure 39). Without a major impacton world oil prices, which is not expected to result from the gradual but significant adoption of natural gas as a fuel for U.S. HDVs, nearly all the reduction in petroleum and other liquids use by U.S . HDVs would be reflected by a decline in imports.

figure data
In the HD NGV Potential case, projected total U.S. natural gas consumption in 2035 is 1.4 trillion cub ic feet (5 percent) higher than in the Reference case, as t he increase in natural gas use by vehicles is partiall y offset by lower consumption in other sectors, in response to higher natural gas prices (Figure 40). The electricpower and industrial sectors account for the bulk of the consumption offsets, as their 2035 natural gas use is, respectively, 0.3 trillion cubic feet (3.1 percent) and 0.2 trillion cubic feet (2.7 percent) lower than in the Reference case.
In 2035, U.S. domestic natural gas production in th e HD NGV Potential case is 1.1 trillion cubic feet (3.9 percent) higher than in the HDV Reference case. The higher l evel of natural gas production needed to support the gro wth in HDV fuel use results in a 10-percent increase in na tural gas prices—$0.76 per million Btu (2010 dollars)—at the Henry Hub in 2035 in comparison with the HDV Re ference case. Percentage increases in delivered natural gas price s to other sectors, which include transmission and distribution costs that are not affected by higher prices to producers, are smaller, with delivered natural gas prices increas ing by 4.9 percent in the residential sector, 5.9 percent in the commercial s ector, 8.9 percent in the industrial sector, and 7. 9 percent in the electricity generation sector in comparison with the HDV Refere nce case in 2035.

figure data


## 7. Changing structure of the refining industry
Petroleum- based liquid fuels represent the largest source of U.S. energy consumption, accounting for about 37 percent of total energyconsumption in 2010. The mix and composition of liquids, however, have changed in re cent years in response to changes in regulations and oth er factors, and the structure of the liquid fuels prod uction industry has changed in response [ 68 ]. The changes in the industry require that analytical tools used formarket analysis of the liquid fuels produced by the indust ry also be reevaluated.

In recognition of the fundamental changes in the li quid fuels production industry, EIA is developing a new Liquid 

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8/9/2012 http://www.eia.gov/forecasts/aeo/IF_all.cfmFuels Market Module (LFMM), which it intends to use in

place of the existing Petroleum Market Module (PMM) to produce the Annual Energy Outlook 2013. The LFM M will allow EIA to address more adequately the current and anticipa ted domestic and international market environments, to analyze the implications of emerging technologies and fuel alte rnatives, and to evaluate the impact of complex eme rging energy-related policy, legislative, and regulatory issues. Some re sults from an early simulation of the LFMM, the LFM M case, are provided here.

The landscape for both production and consumption o f liquid fuels in the United States continues to ev olve, leading to changes in the mix of liquid fuel feedstocks, with greater emphasis on renewable fuels. The liquid fue ls markets are not homogeneous; regional differences have become more pronounced. Furthermore, U.S. policymakers are payi ng more attention to evolving markets for liquid fuels and the potential for improving the efficiency of liqui d fuels consumption, reducing GHG emissions associated with the producti on and consumption of liquid fuels, and improving t he Nation's energy security by reducing reliance on imports. Major ind ustry changes and their implications are discussed below.



### New feedstocks and technologies Over the past 25 years, the U.S. liquid fuels produ ction industry has changed from being based primari ly on domestic petroleum to using a variety of feedstocks and fini shed products from sources around the world. Regula tory and policy changes have resulted in the use of feedstocks othe r than crude oil, such as natural gas and renewable biomass, and could lead to the use of other feedstocks (such as coal) in the coming years. These changes have resulted in a transition from a relatively straightforward supply chain relying on crude oil and finished products to an increasingly complex system, which must be reflected in models to produce valid projec tions.

The term "liquid fuels production industry" refers to all the participants in the production and deliv ery of liquid fuels, from production of feedstocks to delivery of both liquid and non-liquid end-use products to customers. It includes participants in the more traditional petroleum refining sector, relying on crude oil as a primary feedstock; in the nonpet roleum fossil fuel sector, using natural gas and coal to produce liquid fuels; and in the biofuel sector, using biomass to produc e biofuels such as ethanol and biodiesel. The complexity of the indust ry supply chain is inadequately described by nomenc lature predicated on specific feedstocks (e.g., crude oil), processes (e .g. refinery hydrotreating), or end-use products (e .g., diesel fuel and gasoline), which fail to capture the significant ec onomic implications of non-liquid-fuel products forthe industry.
The components of the U.S. liquid fuels production industry—including petroleum, nonpetroleum fossil f uel, and biofuel sectors—are shown in Figure 41, along with examples illustrating processes and products. Figure 41 als o highlights the differences between the new expanded "liquid fuels production industry," which the entire figure repre sents, and the less extensive "petroleum and other liquids industry," t he components of which are highlighted in red.

figure data

Nonpetroleum feedstocks are used in many new and emerging technologies, such as fermentation, enzyma tic conversion, GTL, CTL, biomass-to-liquids, and algae

based biofuels. The new technologies provide valuab le non-liquid-fuel co-products—such as chemical feedstocks, distiller's grains, and vegetable oils—that significantly affect the economics of liquid fuels production. The emergence of renewable biofuels has led to the introduction of midstream components su ch as ethanol and biodiesel, which are blended with petroleum product s such as gasoline and diesel fuel during the final stages of the supply chain at refineries, blending sites, or retail pump s. The increase in biofuel production has led to ne w distribution channels and infrastructure investments and recognition of new p roduction regions, such as the high concentration o f ethanol producers in the Midwest. The new LFMM will include the entire l iquid fuels production industry, providing greater flexibility for integrating new technologies and their associated products into the liquid fuels supply chain, better reflecting t he industry's evolution. 

## Page 27 of 55 U.S. Energy Information Administration (EIA)

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8/9/2012 http://www.eia.gov/forecasts/aeo/IF_all.cfmIn AEO2012 , the "petroleum and other liquids" category includ es the petroleum sector and those non-petroleum-bas ed liquid

products shaded in red in Figure 41, such as ethano l and biodiesel, which are blended with petroleum p roducts to make enduse liquid fuels. Because this approach treats n onpetroleum products as exogenously produced feedst ocks, the petroleum and other liquids concept used in AEO2012 does not explicitly link the industrial processes that yield nonpetroleum liquid fuels (nor their feedstocks, nonpetroleum fo ssil fuels and biomass) with liquids production. Th e more inclusive definition of the liquid fuels production industry illustrated in Figure 41 is necessary to capture and model the fu ll range of product flows and economic drivers of decisionmaking by firms inv olved in this complex industry.

Nonpetroleum feedstocks do not exist in traditional liquid form, and they require a different analytical approach f or analysis of their conversion to liquid fuels. Traditional volum etric measures, such as process gain, are not appli cable to an analysis of the liquids produced from nonpetroleum feedstocks. It is more appropriate to use the fundamental princ iples of mass and energy balance to evaluate process performance, mar ket penetration, and supply/demand dynamics when th e uses of nonpetroleum feedstocks are being examined. This ap proach allows for comparison among the different se ctors of the liquid fuels production industry. Figure 42 provides an ov erview of the liquid fuels production industry on amass basis.

figure data

The variety and changing dynamics of nonpetroleum feedstocks and the resulting end-use products also are illustrated in Figure 42. In recent history, biomas s has taken significant market share from petroleum feedstocks, correlated with shifts in product yield s—a trend that is expected to continue in the future, a long with further diversification into nonpetroleum fossil fe edstocks. In 2000, nearly all liquid fuels were derived from petroleum. Since then, however, the share of petrol eum has dropped while the shares of biomass and other f ossil fuels have increased. In 2011, the combined biomass and other fossil fuels share of feedstocks was almo st 18 percent, measured on a mass basis. In the LFMM case
, the biomass share of feedstock consumption increase s to 30 percent in 2035, and the petroleum share falls t o about 57 percent. The biomass share of end-use products increases only to 10 percent in 2035, refl ecting differences in conversion efficiencies betwe en petroleum and nonpetroleum feedstocks, as highlighted by the grow ing but still small nonpetroleum content of gasolin e and distillates.



### Changes in crude oil types Economic growth in the developing countries over th e past decade has increased global demand for crude oil. Over the same period, new technologies for recovering crude oil, changes in the yields of existing crude oil fi elds, and a global increase in exploration have expanded the number an d variety of crude oil types. The United States cur rently imports more than 100 different types of crude oil from around t he world, including a growing number from Canada and Mexico, with a wide range of API gravities (between 10.4 and 64.6) and sulfur content (between 0.02 and 5.5 percent). Consequently, it is difficult to group them according to the categories used in t he existing NEMS PMM. A new and more comprehensive representation of the numerous crude types is required, as well as flexibility to add new sources.
The United States increasingly is using crude oil e xtracted from oil sands and oil shale, as well as o ther nontraditional petroleum sources that require additional processin g. The new sources have led to shifts in crude oil flows and changes in the distribution network. The increased variety and regional availability of certain crude types has c reated new market dynamics and pricing relationships that are difficu lt to capture using existing methods, especially co nsidering the rapid emergence of "tight oil" production, which, to date , has been substantially different in quality from the crude oil previously 

## Page 28 of 55 U.S. Energy Information Administration (EIA)

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8/9/2012 http://www.eia.gov/forecasts/aeo/IF_all.cfmexpected to be available to U.S. refineries. For ex ample, light sweet crude oil sourced from the Bakke n shale formation in

North Dakota has been sold to refiners on the Gulf Coast in recent years at a substantial discount relative to heavier imported crudes, because of limitations in the delivery infr astructure.
The growing number of sources, changes in character istics of crudes, and shifting price relationships in crude oil markets require an updated representation of different crud e types in NEMS. The model also needs an updated an d more dynamic representation of the crude oil distribution networ k in order to provide better estimates of changes i n crude oil flows and potential new regional sources in the future.



### Regional updates The Petroleum Administration for Defense Districts (PADD), which were developed by the Department of D efense during World War II, have been traditionally used as the r egional framework for analyzing liquid fuels produc tion. Because the topology and configuration of the liquid fuels mark et have changed significantly, and new feedstocks h ave emerged from regions that are subsets of PADDs, the regional def initions for processing liquid fuels need to be red efined. Toward this end, EIA has redefined the refining regions on the basis of market potential and availability of feedstocks . The redefined regions will be further divided as market conditions change . The new regional configuration of the NEMS LFMM will use eight domestic regions and adds a new international regio n (Figure 43).

Each new refining region has unique characteristics

. PADD 1 has been left unchanged in the new configuration, but can be further divided based on recent and possible future refinery closures and shifts in imports from Europe. PADD 2 was subdivided into the Great Lakes and Inland regions due to the concentrated production of biofuels and access to Canadian crude s. PADD 3 was divided into the Gulf Coast and Inland regions due to the inability of the interior refine ries to handle heavy sour crude. PADD 4 was left unchanged. California was separated from the rest of PADD 5 du e to the State's unique gasoline and diesel specificatio ns and regulatory policies. A new international region was added comprising Maritime Canada and the Caribbean.

The modified regional refinery format will allow EI A's analyses to more accurately capture regional re finery trends and potential regional regulatory policies that affect the liquid fuels market. For example, California of ten enacts its own regulatory policies earlier than the rest of its PADD region, and its individual actions could not be represented accurately in the PADD framework. As a further example, recent refinery cl osures and other developments on the East Coast evi dence the need for a dynamic and flexible representation of the refineryregions that supply the U.S. market.



### Changing product markets Crude oil is still the most important and valuable feedstock for the liquid fuels production industry. More than 650 refineries, located in more than 116 countries, have the capaci ty to refine 86 million barrels of crude oil per da y. In the past, most of the complex refineries that could transform a wide vari ety of crudes into numerous different products to m eet demand were located in the United States. Now, however, complex refineries are becoming more common in Europe and the developing countries of Asia and Latin America, and the produc ts from export-focused merchant refineries in those countries have the potential to compete with U.S. products. An example is the regular export of surplus gasoline from ref iners in Europe to the Northeast United States.

Traditional measures of profitability, such as the 3-2-1 crack spread, require modification in NEMS in view of the changing 

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8/9/2012 http://www.eia.gov/forecasts/aeo/IF_all.cfmmarket for liquid fuels. The calculation of margins requires consideration of multiple feedstocks and multiple products

produced in refineries, biorefineries, and producti on facilities for nonpetroleum fuels. Operators in the liquid fuels production industry are faced with a choice of investing in fa cilities and modifying their configurations to meetchanging market demand, or exchanging domestic feedstocks and products with merchant refineries in a global market. For exampl e, increased U.S. efficiency standards for LDVs have reduced demand f or gasoline and increased demand for diesel fuel, w hich has led to more gasoline exports and more investment to increa se diesel output from domestic refineries.

EIA's new LFMM representation of the liquid fuels p roduction industry will need to account for global competition for both crude oil and end-use products. As refineries aroun d the world become larger and more complex, smallerrefineries may not be able to compete with imports produced at low mar gins. Therefore, it is necessary to have a more rob ust and dynamic representation of the liquid fuel producers, as wel l as additional flexibility to adjust inputs, refin ery configurations, and crude and product demands as the industry evolves.



### Regulations and policies It is important for EIA's models to represent exist ing laws and regulations accurately, in addition to being flexible enough to model proposed laws and regulations. One of the mos t important regulations currently affecting the U.S . liquid fuels industry is the RFS, which not only has increased production and use of renewable fuels, but also has changed h ow fuels are distributed and consumed both here and abroad. The RFS mandates the use of biofuels that are consumed primarily as blends with traditional petroleum products, such as gasoline and diesel fuel (Figure 44). Because of t heirchemical properties, ethanol, biodiesel, and other first-generation biof uels generally require their own distribution netwo rks or investments in new infrastructure. In addition, because they are produ ced outside traditional petroleum refineries, the n ew products are added at different points in the supply chain, either at ble nding terminals or at retail sites via blender pump s. Modeling those changes requires an update to the traditional PADD regional format used to represent the liquid fuels market, as well as an update to the transportation network that distributes the fue ls.

figure data
The RFS also requires consideration of many new technologies and increases the complexity of decisionmaking in the liquid fuels production indus try. Fuel volumes by product are mandated by the RFS. Fo r each year, regulated parties must make the decision to either buy the available renewable fuels in proport ion to their RFS requirements or purchase the necessary credits. For example, the cellulosic biofuel creditprice is set as the greater of $0.25 cents per gallon or $3. 00 per gallon minus the wholesale gasoline price, both bas ed on 2008 real dollars. The RFS also contains a general waiver based on technical, economic, or environment al feasibility that the EPA Administrator has discreti onary authority to acton on to reduce the mandates for advanced and total biofuels.

In addition, use of biofuels has broader implicatio ns for the global market, in terms of both feedstoc ks and the fuels themselves. A good example is ethanol. Its primary feedstocks are corn and sugar, both of which are gl obal commodities in high demand as food sources as well as biofuel feed stocks. U.S. ethanol producers compete globally in other countries, suc h as Brazil, that have their own renewable fuels mand ates.
Finally, coproducts from biofuels production have asignificant influence on their economics. For exam ple, the value of the dried distillers grains coproduct from corn ethanol production, which can be sold to the agricultural sector, can offset up to 

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8/9/2012 http://www.eia.gov/forecasts/aeo/IF_all.cfmone-third of the purchase cost for the corn feedsto ck. Thus, the economics of biofuels production are complex, and they

require a model that accounts for numerous investme nt decisions, feedstock markets, and global interactions. The RF S adds to the liquids fuels market a number of fuel techno logies, midstream products and coproducts, evolving regional production and distribution networks, and complex domestic and global market interactions.
The U.S. liquid fuels market has evolved substantia lly over the past 20 years in terms of available fu el types, production regions, global market dynamics, and regulations an d policies. The transition has resulted in a liquid fuels market that uses both petroleum and nonpetroleum-based inputs, distr ibutes them around the country by a variety of meth ods, and makes investment decisions based on both economic and reg ulatory factors. The changes are significant enough to make the framework and metrics used in traditional refinery models no longer adaptable or robust enough for pro per modeling of the transformed liquid fuels market. EIA currently is i n the process of updating its framework to allow be tter representation of the transformed industry.


## 8. Changing environment for fuel use in electricitygeneration

Introduction The AEO2012

Reference case shows considerable change in the mi x of generating technologies over the next 25 years

. Coal remains the dominant source of electricity gen eration in the Reference case, with a 38-percent sh are of total generation in 2035, but that is down from shares of 45 percentin 2010 and nearly 50 percent in 2005. The decreas e in coal's share of total generation is offset primarily by increases i n the shares of natural gas and renewables. Key fac tors contributing to the shift away from coal are sustained low natural gas prices, higher coal prices, slow growth in electric ity demand, and the implementation of Mercury and Air Toxics Standards (MATS) [ 69 ] and Cross-State Air Pollution Rule (CSAPR) [ 70 ]. These factors influence how existing plants are used, whi ch plants are retired, and what types of new plants are built.



### Fuel prices and dispatch of power plants The price of fuel is a major component of a power p lant's variable operating costs [ 71 ]. The fuel-related variable cost of generating electricity is a function of the fuel pr ice and the efficiency of the plant's conversion ofthe fuel into electricity, also referred to as the heat rate. Although natural gas prices declined dramatically in the second half of 2011 and the first half of 2012, coal-fired power plants have generally had th e advantage of lower fuel prices and the disadvanta ge of higher heat rates in comparison to combined-cycle plants fueled by natural gas.

Power plants are dispatched primarily on the basis of their variable costs of operation. Plants with t he lowest operating costs generally operate continuously. Plants with higher variable costs are brought on line sequentially as demand for generation increases. Because fuel prices influence variable c osts, changes in fuel prices can affect the choice of plants dispatched. For instance, if the price of natural gas decreases, th e variable costs for combined-cycle plants may fall below those for competing coal-fired plants, and, as a result, the combined-cycle plant may be dispatched before the c oal-fired plant. Coal and natural gas plants can vary their outputs on th e basis of fuel prices, but there are some cases in which plants may cycle off completely until they can be operated economica lly. In order to examine the overall impacts of cha nges in projected fuel price trends on the electric power sector, AEO2012 includes alternative cases that assume higher and lower prices for natural gas and coal.



### Demand for electricity Electricity demand determines how much generating c apacity is needed. When demand increases, plants wi th higher operating costs are brought into service, increasin g average operating costs and, as a result, average electricity prices. Higher prices, in turn, provide economic incentives for the construction of new capacity. Conversely, when demand declines, plants with higher operating costs are taken off li ne or run at lower intensities, and the economic in centives for new plant construction are reduced. If a plant is not profita ble, the owner may decide to retire it.



### Mercury and Air Toxics Standards and Cross-State Ai r Pollution Rule 

## Page 31 of 55 U.S. Energy Information Administration (EIA)

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8/9/2012 http://www.eia.gov/forecasts/aeo/IF_all.cfmBoth MATS and CSAPR are included in the AEO2012 Ref erence case [ 72 ]. Both rules have significant implications for the

U.S. generating fleet, especially coal-fired power plants. MATS requires all U.S. coal- and oil-fired power plants with capacities greater than 25 megawatts to meet emissi on limits consistent with the average performance o f the top 12 percent of existing units—known as the maximum achievable c ontrol technology. MATS applies to three pollutants : mercury, hydrogen chloride (HCl), and fine particulate matte r (PM2.5). HCl and PM2.5 are intended to serve as surrogate pollutants for acid gases and nonmercury metals, respectively. CSA PR is a cap-and-trade program that sets caps on sul fur dioxide (SO 2 ) and nitrogen oxide (NO x ) emissions from all fossil-fueled plants greater t han 25 megawatts in 28 States in most of the eastern half of the United States. CSAPR is schedul ed to begin in 2012, although implementation was de layed by a courtissued stay at the time this article was completed [ 73 ]. See also "Cross-State Air Pollution Rule" in the "Legislation and regulations" section of this report.

Although the two rules differ in their makeup and t he pollutants covered, the technologies that can be used to meet their requirements are not mutually exclusive. For instan ce, in order to meet the MATS acid gas standard, itis assumed that coalfired plants without appropriate existing controls will need to install either flue-gas desulfurizatio n (FGD) or dry sorbent injection (DSI) systems, which also reduce SO 2 emissions. Therefore, bycomplying with the MATS standards for acid gases, plants will lower overall SO 2 emissions, facilitating compliance with CSAPR.

AEO2012

assumes that all coal-fired power plants will be r equired to reduce mercury emissions to 90 percent b elow their precontrol levels in order to comply with MATS. The AEO2012 NEMS explicitly models mercury emissions from power plants. Reductions in mercury emissions can be achieved wit h a combination of FGDs and selective catalytic red uction, which is primarily used to reduce SO 2 and NO xemissions, or by installing activated carbon injec tion (ACI) systems. FGD systems may be effective in reducing mercury emissions from bituminous coal (due to its chemical makeup), but ACI systems may be necessary to remove mercury emissions from plants b urning subbituminous and lignite coal.
NEMS does not explicitly model emissions of acid ga ses or toxic metals other than mercury. In order to represent the MATS limits for those emissions, AEO2012 assumes that plants must install either FGD or DSI systems to meet the acid gas standard and, in the absence of a scrubber, a full fabric filter to meet the MATS standard for nonmerc ury metals. AEO2012 assumes that the appropriate control technologies w ill be installed by 2015 in order to meet the MATS requirements.
DSI and wet and dry FGD systems are technologies th at will allow plants to meet the MATS standards foracid gases. As of 2010, 43 percent of U.S. generating capacity alread y had FGDs installed [ 74 ]. For a number of the remaining, uncontrolled plants, operators will need to assess the effective ness of installing FGD or DSI systems to comply wit h MATS. There are economic and engineering tradeoffs between the two technologies. FGD systems require significant upfro nt investment but have relatively low operating costs. DSI systems ge nerally do not require significant capital expenses but may use significant quantities of sorbent to operate effectively, which increases their operating costs. Waste disposal fo r DSI also may be a significant variable cost, whereas the waste produc ts from FGD systems can be sold as feedstock for in dustrial processes.

The EPA set an April 2015 compliance deadline for M ATS, but the rule allows State environmental permit ting agencies to extend the deadline by a year. Beyond 2016, the EPAstated that it will handle noncompliant units thatneed to operate for reliability purposes on a case-by-case basis [ 75 ]. AEO2012 assumes that all plants will comply with MATS by t he beginning of 2015.



### Economics of plant retirements The decision to retire a power plant is an economicone. Plant owners must determine whether a plant's futu re operations will be profitable. Environmental regulations, low natur al gas prices, higher coal prices, and future deman d for electricity all are key factors in the decision. Coal plants without FG D systems and with high heat rates, high delivered coal costs, and strong competition from neighboring natural gas plants in regions with slow growth in electricity demand may be especially prone to retirement.



### Greenhouse gas policy in AEO2012 

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8/9/2012 http://www.eia.gov/forecasts/aeo/IF_all.cfmUncertainty about possible future regulation of GHG emissions will continue to influence investment de cisions in the power

sector. Despite a lack of Congressional action, man y utilities include simulations with a future CO 2 emissions price when evaluating long-term investment decisions. A carbon price would increase the cost of generation for al l fossil fuel plants, but the largest impact would be on coal-fired plants. T hus, plant owners could be reluctant to retrofit ex isting coal plants to control for non-GHG pollutants, given the possibili ty that GHG regulations might be enacted in the nea r future. This uncertainty may influence the assumptions plant own ers make about the economic lives of particular fac ilities.

In the Reference case, the costs of environmental r etrofits are assumed to be recovered over a 20-yearperiod. Two alternative cases assume that the costs would be re covered over 5 years, reflecting concern that futur e laws or regulations aimed at limiting GHG emissions will have significa nt negative effects on the economics of investing i n existing coal plants.

AEO2012

also includes two alternative cases that assume en actment of an explicit GHG control policy. In each case, a CO 2 price is applied across all sectors starting in 201 3 and increased at a 5-percent annual real rate thr ough 2035. The price starts at $25 per metric ton in the GHG25 case and $15 per metric ton in the GHG15 case. The CO 2 price is applied across sectors and has a significant impact on the cost ofgenerating electricity from fossil fuels, particul arly coal.



### Alternative cases

figure data

In order to illustrate the impacts of the various i nfluences on the electric power sector, AEO2012 includes several alternative cases that include varying assumptions about fuel prices, electricity demand, and the cost recov ery period for environmental control equipment investme nts:

 The Reference 05 case assumes that the cost recovery period for investments in new environmenta l controls is reduced from 20 years to 5 years.

 The Low Estimated Ultimate Recovery (EUR) case assumes that the EUR per tight oil or shale gas wel l is 50 percent lower than in the Reference case, increasing the per-unit cost of developing the resource and, ultimately, the price of natural gas used at power plants (Figure 45).

 The High EUR case assumes that the EUR per tight oi l or shale gas well is 50 percent higher than in th e Reference case, decreasing the per-unit cost of developing th e resource and the price of natural gas for power p lants.

 The Low Gas Price 05 case combines the more optimis tic assumptions about future volumes of shale gas p roduction from the High EUR case with a 5-year recovery perio d for investments in new environmental controls.

 The High Coal Cost case assumes lower mining produc tivity and higher costs for labor, mine equipment, and coal transportation, which ultimately result in higher c oal prices for electric power plants.

 The Low Coal Cost case assumes higher mining produc tivity and lower costs for labor, mine equipment, a nd coal transportation, which ultimately result in lower co al prices for electric power plants.

 The Low Economic Growth case assumes lower growth r ates for population and labor productivity, higher interest rates, and lower growth in industrial output, which ultimately reduce demand for electricity (Figure 4 6), which is reflected in electricity sales, relative to the Ref erence case.

figure data

 The High Economic Growth case assumes higher growth rates for population and labor productivity. 

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8/9/2012 http://www.eia.gov/forecasts/aeo/IF_all.cfmWith higher productivity gains and employment

growth, inflation and interest rates are lower than in the Reference case, and, consequently, economicoutput grows at a higher rate, ultimately increasing demand for electricity, which is reflected in electricity sale s, relative to the Reference case.

 In the GHG15 case, the CO 2 price is set at $15 per metric ton in 2013 and inc reases at a real annual rate of 5 percent per year over the projection period. Price is set t o target the same reduction in CO2 emissions as in the AEO2011 GHG Price Economywide case.

 In the GHG25 case, the CO 2 price is set at $25 per metric ton in 2013 and inc reases at a real annual rate of 5 percent per year over the projection period. Price is set t o target the same dollar amount as in the AEO 2011 GHG Price Economywide case.



### Analysis results

Coal-fired plant retirements

figure data
Significant amounts of coal-fired generating capaci ty are retired in all the alternative cases considered (Fi gure 47). (For a map of the electricity regions projected, se e Appendix F.) In the Reference 05 case, 63 gigawatts of coal-fired capacity is retired through 2035, 28 per cent higher than in the Reference case. In the High EUR case, 55 gigawatts of coal-fired capacity is retired, as lower wholesale electricity prices and competition from n atural gas combined-cycle units makes the operation of som e coal plants uneconomical. In the Low Economic Growt h case, 69 gigawatts of coal-fired capacity is retire d, because lower demand for electricity reduces the ne ed for new capacity and makes investments in older pla nts unattractive.
The High Economic Growth case results in fewer retirements, as existing coal-fired capacity is nee ded to meet growing electricity demand, and higher economic growth pushes up natural gas prices. In the Low Coal Cost case, the lower relative coal prices increase the p rofit margins for coalfired power plants, making it more likely that inve stments in retrofit equipment will be recouped overthe life of the plants.
Coal-fired capacity retirements are concentrated in two North American Electric Reliability Corporatio n (NERC) regions: the SERC Reliability Corporation (SERC) region, which c overs the Southeast region, and the Reliability Fir st Corporation (RFC), which includes most of the Mid -Atlantic and Ohio Valley region [ 76 ]. Many coal-fired plants in those regions are sens itive to the factors that influence retirement decisions, as discussed above. In the SERC and RFC regions, whic h in 2010 accounted for 65 percent of U.S. coal-fired generating capaci ty, 43 percent of the coal-fired plants do not have FGD units installed. Coal plants in the RFC and SERC regions are fueled prima rily by bituminous coal, generally the coal with th e highest cost. Projected demand for electricity in the early years ofthe Reference case is low nationwide and, especial ly, in the RFC region, where demand in 2015 is slightly lower than in 2010. In both the GHG15 and GHG25 cases, even larger amounts of coalfired capacity are retired by 2035 than in the non- GHG policy cases.



### Generation by fuel

Coal 

## Page 34of 55 U.S. Energy Information Administration (EIA)

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8/9/2012 http://www.eia.gov/forecasts/aeo/IF_all.cfmIn all cases, generation from coal is lower in 2020 than in 2010. Higher coal prices, relatively low n atural gas prices,

retirements of coal-fired capacity, and slow growth in electricity demand are responsible for the decr ease. Generation from coal is lower than in the Reference case in the Ref erence 05, High EUR, Low Gas Price 05, High Coal Co st, and Low Economic Growth cases as a result of additional ret irements of coal-fired capacity, lower natural gas prices, higher coal prices, or lower electricity demand. In cases where the opposite assumptions are incorporated, coal-fi red generation is higher.
Generation from coal begins to recover after 2020, as electricity demand and natural gas prices start to rise. The strongest increases in coal-fired electricity generation occu r in the Low EUR, Low Coal Cost, and High Economic Growth cases. When lower natural gas prices, lower economic growth, an d/or higher coal prices are assumed, coal-fired gen eration still increases after 2020 but at a slower rate. In all cases, util ization of existing coal-fired power plants increas es, because there is no significant growth in new coal-fired capacity. In t he most optimistic case, the High Economic Growth c ase, only 3.3 gigawatts of new coal-fired capacity is added from 2017 to 20 35 [ 77 ].

Despite a declining share of the generation mix, co al still has the highest share of total electricitygeneration in 2035 in all non-GHG or High TRR cases. However, it never again reaches the 2010 share of 45 percent, even in the L ow EUR case (where it reaches 40 percent in 2035). Conversely, the coal share of total generation in 2035 is 34 pe rcent in the Low Gas Price 05 case. The lower coal share is offset by in creased generation from natural gas, which grows si gnificantly in all the cases. The natural gas share of total generation al most equals that of coal in the Low Gas Price 05 ca se. In the GHG15 and GHG25 cases, coal-fired generation drops to 16 perc ent and 4 percent, respectively, of the total gener ation mix in 2035, and in both cases generation from coal declines signifi cantly as the explicit price on CO 2 emissions increases costs. In the GHG15 and GHG25 cases, decreases in coal-fired gene ration are offset by a mix of natural gas, nuclear, and renewable generation.



### Natural gas

figure data

In the AEO2012

Reference case, electricity generation from natural gas in 2020 is 13 percent above the 20 10 level, despite an increase of only 5 percent in ove rall electricity generation. Low natural gas prices resu lt in greater utilization of existing combinedcycle plant s as well as the addition of 16 gigawatts of natural gas combined-cycle capacity from 2010 to 2020. The same trends are amplifed in cases with lower natural gas prices and more coal-fired capacity retirements and muted in cases with higher natural gas prices and fewer coal -fired capacity retirements. Generation from combustion turbines does not change significantly across the c ases, demonstrating that changes in the relative economic s of coal and natural gas affect primarily the dispatch of combined-cycle plants to meet base and intermediate load requirements, not combustion turbines to meet peak load requirements.

figure data

In the Reference case, 58 gigawatts of natural gas combinedcycle capacity is added from 2020 to 2035, 

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8/9/2012 http://www.eia.gov/forecasts/aeo/IF_all.cfmcausing an increase in generation from natural gas during

the period (Figures 48 and 49). In the Low EUR and Low Coal Cost cases, growth in natural gas combined -cycle capacity is slower. Although generation from natural gas increa ses overall with the addition of new capacity, util ization of existing combined cycle plants drops slightly as higher natu ral gas prices reduce the frequency at which combin ed-cycle plants are dispatched.
In the GHG15 and GHG25 cases, electricity generatio n from natural gas exceeds generation from coal in 2020. Natural gas has one-half the CO 2 emissions of coal, and at relatively low CO 2 prices, natural gas generation is seen as an attra ctive alternative to coal. However, as CO 2 prices rise over the projection period, the increa sing cost of generating electricity with natural gas causes the growth in natural gas genera tion to slow. In the GHG25 case, natural gas combin ed-cycle plants with CCS play a role in CO 2 mitigation, with 34 gigawatts of natural gas combi ned-cycle capacity added between 2022 and 2035.



### Nuclear Generation from nuclear power plants does not chang e significantly from Reference case levels in any o f the non-GHG cases, due to the high cost of new nuclear plant co nstruction relative to natural gas and renewables. In the GHG15 and GHG25 cases, nuclear power plants become more compe titive with fossil plants, because they do not emit CO 2 and are needed to replace coal-fired capacity that is retir ed due to the cost of CO 2 emissions. In the GHG15 and GHG25 cases, generation from nuclear power is 57 percent and 121 percent higher, respectively, in 2035 than in 2010

.



### Renewables Generation from renewable energy sources grows by 7 7 percent from 2010 to 2035 in the Reference case. Most of the growth in renewable electricity generation is a res ult of State RPS requirements, Federal tax credits, and—in the case of biomass—the availability of low-cost feedstocks. Th e change in renewable generation over the 2010- 2035 period varies from a 102-percent increase in the High Economic Growth case to a 62-percent increase in the Low Economic G rowth case. The largest growth in renewable generation is projected in the GHG15 and GHG25 cases, where renewable generation increases by about 150 percent from 2010 and 2035 in both cas es. A price on CO 2 emissions makes generation from renewables more competitive with fossil plants without CCS.



### Installations of retrofit equipment

figure data

As discussed above, it is assumed that all coal-fir ed plants must have either FGD or DSI systems installe d by 2015 to comply with environmental regulations. Beca use retirement is the only other option, cases with mor e retirements have fewer retrofits and vice versa (Fi gure 50). In the Reference 05 and Low Gas Price 05 cases
, the relative cost of FGD units is higher because ofthe short payback period, making DSI a relatively more attractive option.



### Emissions SO 2 emissions are significantly below 2010 levels in 2015 in all cases, as a result of coal-fired capaci ty retirements and the installation of pollution contr ol equipment to comply with MATS. AEO2012 assumes that a DSI system, combined with a fabric filter, will r emove 70 percent of a coal plant's SO 2 emissions, and an FGD unit 95 percent. As a resultof the requirement for FGD or DSI systems, all coal plants larger than 25 megawatts t hat did not have FGD units installed in 2010 signif icantly reduce their SO 2 

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8/9/2012 http://www.eia.gov/forecasts/aeo/IF_all.cfmemissions after 2015 by installing control equipmen t. In all cases, coal-fired generation is down over all, which also

contributes to the decline in emissions. SO 2 emissions increase after 2020 in all non-GHG cases , as coal-fired generation increases with rising natural gas prices. Because D SI and FGD retrofits do not remove all the SO 2 from coal-fired power plant emissions, increases in coal-fired generation result in higher SO 2 emissions, although they are still much lower than comparable 2010 levels. Also, the level of SO 2 reduction is proportional to the amount of coal-fi red generation, and therefore the cases with the highest projected levels of coal -fired generation also project the highest levels o f SO 2 emissions.

The projections for mercury emissions are similar. After a sharp drop in 2015, mercury emissions begin to rise slowly as coalfired generation increases in all non-GHG cases. Ho wever, mercury emissions in 2035 still are signific antly below 2010 levels, as the requirement for a 90-percent reducti on in uncontrolled emissions of mercury remains bin ding throughout the projection.

NO xemissions are not directly affected by MATS, but b oth annual and seasonal cap-and-trade programs are included in CSAPR. Emissions reductions relative to 2010 levels are small throughout the projection period in mostcases, mainly because compliance with CSAPR NO xregulations is required in only 26 States, and 201 0 emissions levels already were close to the cap.

CO 2 emissions from the electric power sector fall slig htly in cases that project declines in coal use, bu t the largest reductions occur in the GHG15 and GHG25 cases. In the GHG15 ca se, CO 2 emissions from the electric power sector are 46 pe rcent below 2010 levels in 2035, and in the GHG25 case th ey are 76 percent below 2010 levels.



### Electricity prices Real electricity prices in 2035 are 3 percent above the 2010 level in the Reference case. The increase is relatively modest because natural gas prices increase slowly, and sev eral alternatives for complying with the environmen tal regulations are available. When lower natural gas prices are assume d, real electricity prices decline relative to the Reference case. Both the GHG15 and GHG25 cases assume that costs for CO 2 emission allowances are passed through directly to customers. Therefore, average electricity prices in the GHG15 and GHG25 cases in 2035 are 25 percent and 33 perce nt higher, respectively, than in the Reference case. The GHG15 and GHG25 cases do not include any of the rebates to electricity consumers included in some other GHG policy proposa ls, which would reduce the impact on electricity pr ices.


## 9. Nuclear power in AEO2012
In the AEO2012

Reference case, electricity generation from nuclea r power in 2035 is 10 percent above the 2010 total. The nuclear share of overall generation, however, decli nes from 20 percent in 2010 to 18 percent in 2035, reflecting increased shares for natural gas and renewables.

In the Reference case, 15.8 gigawatts of new nuclea r capacity is added from 2010 through 2035, includi ng both new builds (a total of 8.5 gigawatts) and power uprates at ope rating nuclear power plants (7.3 gigawatts). A tota l of 6.1 gigawatts of nuclear capacity is retired in the Reference case, with most of the retirements coming after 2030. How ever, given the current uncertainty about likely lifetimes of nuclear plant s now in operation and the potential for new builds
, AEO2012 includes several alternative cases to examine the impacts ofdifferent assumptions about future nuclear power p lant uprates and operating lifetimes.



### Uprates Power plant uprates involve projects that are inten ded to increase the licensed capacity of existing n uclear power plants and permit those plants to generate more electricity. T he U.S. Nuclear Regulatory Commission (NRC) must ap prove all uprate projects before they are undertaken and verify thatthe reactors will be able to operate safely at hig herlevels of output. Power plant uprates can increase plant capacity by 1 to 2 0 percent, depending on the size and type of the up rate project. Capital expenditures may be small (e.g., installing a more accurate sensor) orsignificant (e.g., replacing key plant components, such as turbines). 

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8/9/2012 http://www.eia.gov/forecasts/aeo/IF_all.cfmIn developing projections for nuclear power, EIA re lies on both reported data and estimates. Reported data come from Form

EIA-860 [ 78 ], which requires all nuclear power plant owners to report any plans for building new plants or making major modifications to existing plants (such as uprates) over the next 10 years. In 2010, operators reported that they intended to complete uprate projects sometime during the next 1 0 years, which together would add a total of 0.8 gi gawatts of new capacity. In addition to the reported plans for cap acity uprates, EIA assumed that additional power up rates over the period from 2011 to 2035 would add another 6.5 gigawatts o f capacity, based on interactions with EIA stakehol ders with significant experience in implementing power plant uprates.



### New builds Building a new nuclear power plant is a tremendousl y complex project that can take many years to compl ete. Specialized highwage workers, expensive materials and component s, and engineering and construction expertise are r equired, and only a select group of firms worldwide can provide them. In the current economic environment of low natural gas prices and flat demand for electricity, the overall market conditio ns for new nuclear power plants are challenging.

Nuclear power plants are among the most expensive o ptions for new generating capacity available today [ 79 ]. In the AEO2012

Reference case, the overnight capital costs associ ated with building a nuclear power plant planned in 2012 are assumed to be $5,335 per kilowatt of capacity, whic h translates to $11.7 billion for a dual-unit 2,200 -megawatt power plant. The overnight costs do not include additional costs such as financing, interest carried forward, and p eripheral infrastructure updates [ 80 ]. Despite the cost, however, deployment of new nuc lear capacity supports the long-term resource plans of many utilities, by allowing fuel diversification and pro viding a hedge in the future against potential GHG emissions regulations or natural gas prices that are higher than expected.

Incentive programs exist to encourage the construct ion of new reactors in the United States. At the Fe deral level, the Energy Policy Act of 2005 (EPACT05) established a loan gua rantee program for new nuclear plants completed and in operation by 2020 [ 81 ]. A total of $18.5 billion is available, of which $8.3 billion has been conditionally committed to th e construction of Southern Company's Vogtle Units 3 and 4 [ 82 ]. EPACT05 also provides a PTC of $18 per megawatth our for electricity produced during the first 8 years of operation for a new nuclear plant [ 83 ]. New nuclear plants must be operational by 2021 to be eligible for the PTC, and the credit is limited to the first 6 gigawatts of new nuclear plant capac ity. In addition to Federal incentives, several States provide favorable regula tory environments for new nuclear plants by allowin g plant owners to recover their investments through retail electricit y rates.
Several utilities are moving forward with plans to deploy new nuclear power plants in the United State s. The Reference case reflects those plans by including 6.8 gigawatts of new nuclear capacity over the projection period. As reported on Form EIA860, 5.5 gigawatts of new capacity (Vogtle Units 3 and 4, Summer Units 2 and 3, and Watts Bar Unit 2) are expected to be operational by 2020 [ 84 ]. The Reference case also includes 1.3 gigawatts a ssociated with the construction of Bellefonte Unit 1, which the Tennessee Valley Authority reflects in its Integrated Resource Plan [ 85 ].

In addition to reported plans for new nuclear powerplants, 1.8 gigawatts of unplanned capacity is bui lt in the later years of the Reference case. Higher natural gas prices, reco vering demand for electricity, and the need to make up for the loss of a limited amount of nuclear capacity all play a role in the additional builds.



### Long-term operation of the existing nuclear power f leet The NRC has the authority to issue initial operatin g licenses for commercial nuclear power plants for a period of 40 years. As of December 31, 2011, there were 7 reactors that re ceived their initial full power operating licenses over 40 years ago. Among this set of reactors, Oyster Creek Unit 1 was the first reactor to operate for over 40 years, af ter receiving its initial full power operating license in August 1969. Oyster Cree k Unit 1 was followed by Dresden Units 2 and 3, H.B . Robinson Unit 2, Monticello, Point Beach 1, and R.E. Ginna. The deci sion to apply for an operating license renewal is m ade by nuclear power plant owners, typically based on economics and the ability to meet NRC requirements. As of January 201 2, the NRC had granted license renewals to 71 of the 104 operating reactors in the United States, allowing them to op erate for a total of 60 years [ 86 ]. Currently, the NRC is reviewing license renewal applications for 15 reactors and expects to receive applications from another 14 reactors between 2012 and 2016 [ 87 ]. 

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8/9/2012 http://www.eia.gov/forecasts/aeo/IF_all.cfmNRC regulations do not limit the number of license renewals a nuclear power plant may be granted. The nuclear power

industry is preparing applications for license rene wals that would allow continued operation beyond 60 years. The first application seeking approval to operate for 80 year s is tentatively scheduled to be submitted by 2013. Some aging nuclear plants may, however, pose a variety of issues that could lead to decisions not to apply for a second l icense renewal, such as high operation and maintenance costs or the need fo r large capital expenditures to meet NRC requiremen ts. Industry research on long-term reactor operations and aging management is focused on identifying challenges tha t aging facilities might encounter and formulating potential approache s to meet those challenges [ 88 ]. Typical challenges involve materials degradation, safety margins, and assessing the inte grity of concrete structures. In the Reference case , 6.1 gigawatts of nuclear power plant capacity is retired by 2035, ba sed on uncertainty related to issues associated wit h long-term operations and aging management [ 89 ].
It should be noted that although the Oyster Creek G enerating Station in Lacey Township, New Jersey, re ceived a license renewal and could operate until 2029, the plant's o wner has reported to EIA that it will be retired in 2019, after 50 years of operation. The AEO2012 Reference case includes this reported early retire ment. Also, given the evolving nature of the NRC's regulatory response to the accident at Japan' s Fukushima Daiichi nuclear power plant in March 20 11, the Reference case does not include retirements directly related to the accident (for example, retirements prompted by potential new NRC regulatory requirements for safety retrofits).



### Sensitivity cases

figure data

The AEO2012

Low Nuclear case assumes that only the planned nuclear plant uprates already reported to E IA will be completed. Uprates that are currently under revi ew or expected to be submitted to the NRC are not include d. The Low Nuclear case also assumes that all nuclear power plants will be retired after 60 years of oper ation, resulting in a 30.9-gigawatt reduction in U.S. nucl ear power capacity from 2010 to 2035. Figure 51 shows nuclear capacity retirements in the Low Nuclear cas e by NERC region. It should be noted that after the reti rement of Oyster Creek in 2019, the next nuclear plant retirement occurs in 2029 in the Low Nuclear case. No new nucl ear plants are built in the Low Nuclear case beyond the 6.8 gigawatts already planned.

In the High Nuclear case, in addition to plants alr eady under construction, plants with active license appl ications at the NRC are constructed, provided that they have a tentatively scheduled mandatory hearing before the NRC or Atomi c Safety and Licensing Board and deploy a currently certified design for the nuclear steam supply system, such as the AP 1000. With this assumption, an additional 6.2 gigaw atts of new nuclear capacity is added relative to the Reference case. T he High Nuclear case also assumes that all existing nuclear power plants will receive their second license renewals and will operate through 2035. Uprates in the High Nuc lear case are consistent with those in the Reference case. The only retirement i ncluded in the High Nuclear case is the announced e arly retirement of Oyster Creek in 2019.



### Results In the Reference case, 8.5 gigawatts of new nuclearpower plant capacity is added from 2010 to 2035, i ncluding the 6.8 gigawatts reported to EIA (referred to as "planned" ) and 1.8 gigawatts built endogenously in NEMS (ref erred to as "unplanned"). Unplanned capacity is added starting in 2030 in response to rising natural gas prices, whi ch make new nuclear 

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8/9/2012 http://www.eia.gov/forecasts/aeo/IF_all.cfmpower plants a more competitive option for new electric capacity. In the High Nuclear case, planned ca pacity additions are

almost double those in the Reference case, but unpl anned additions are lower. The price of natural gas delivered to the power sector in the High Nuclear case is lower than in the Reference case, making the economics of nuc lear power plants slightly less attractive. The additional planned ca pacity in the High Nuclear case also reduces the ne ed for new unplanned capacity. No unplanned capacity is added in the LowNuclear case.

Nuclear power generation in 2035 reflects the diffe rences in capacity that occur in the nuclear cases. In the High Nuclear case, nuclear generation in 2035 is 10 percent high er than in the Reference case, and the nuclear share of total generation is 20 percent, as compared with 18 percent in the Refe rence case. The increase in nuclear capacity in the High Nuclear case contributes to an increase in total electricity gen eration, in spite of lower levels of generation fro m natural gas (4 percent lower than in the Reference case in 2035) and coal and renewables (less than 1 percent lower for each fuel).

In the Low Nuclear case, generation from nuclear po wer in 2035 is 30 percent lower than in the Referen ce case, due to the loss of 30.9 gigawatts of nuclear capacity that is retired after 60 years of operation. As a result, t he nuclear share of total generation is reduced to 13 percent. The loss of ge neration is made up primarily by increased generati on from natural gas (12 percent higher than in the Reference case in 20 35), coal (1 percent higher), and renewables (3 per cent higher).

Real average electricity prices in 2035 are 1 perce nt lower in the High Nuclear case than in the Refer ence case, as slightly less natural gas capacity is dispatched, lowering t he marginal price of electricity. In the Low Nuclea r case, average electricity prices in 2035 are 5 percent higher than in the Ref erence case as a result of the retirement of a sign ificant amount of nuclear capacity, which has relatively low operating costs, and its replacement with natural gas capacity, whi ch has higher fuel costs that are passed through to consumers in retail elec tricity prices. With all nuclear power plants being retired after 60 years of operation in the Low Nuclear case, an additional 12 gigawatts of nuclear capacity would be shut down b etween 2035 and 2040.
The impacts of nuclear plant retirements on retail electricity prices in the Low Nuclear case are more apparent in regions with relatively large amounts of nuclear capacity. For e xample, electricity prices in the Low Nuclear case are 7 percent higher than in the Reference case for the NERC MRO Region, and 6 percent higher in the Northeast, Mid-Atlantic, an d Southeast regions. Even in regions where no nuclear capacity is retired, there are small increases in electricit y prices relative to the Reference case, because higher demand for natural g as in regions with nuclear plant retirements affectprices nationwide.
The Reference case projections for CO 2 emissions also are affected by changes in assumpti ons about nuclear plant lifetimes. In the Low Nuclear case, CO 2 emissions from the electric power sector in 2035 a re 3 percent higher than in the Reference case as a result of switching from nuclea r generation to natural gas and coal, both which pr oduce more CO 2 emissions. In the High Nuclear case, CO 2 emissions from the power sector are slightly (1 pe rcent) lower than in the Reference case. Table 12 summarizes key results from the AEO2012 Reference, High Nuclear, and Low Nuclear cases.


## 10. Potential impact of minimum pipeline throughputconstraints on Alaska North Slope oil production

Introduction Alaska's North Slope oil production has been declin ing since 1988, when average annual production peak ed at 2.0 million barrels per day. In 2010, about 600,000 barrels perday of oil was produced on the North Slope. Althou gh new North Slope oil fields have started production since 1988, the decline of North Slope production has resulted larg ely from depletion of the North Slope's two largest fields, Prudhoe Bay and K uparuk River. Recently, Alyeska Pipeline Service Co mpany (Alyeska), the operator of the Trans-Alaska Pipeline System (T APS), stated that oil pipeline transportation probl ems could begin when throughput falls below 550,000 barrels per day and become increasingly severe with further declines [ 90 ].
Alyeska estimates that TAPS operational problems co uld become considerable when throughput falls below350,000 barrels per day. The decline of both North Slope oil produc tion and TAPS throughput raises the possibility tha t North Slope oil production might be shut down, with the existing oi l fields plugged and abandoned sometime before 2035 . That possibility is 

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8/9/2012 http://www.eia.gov/forecasts/aeo/IF_all.cfmdiscussed here, as well as alternatives that could prolong the life of North Slope oil fields and TAPS beyond 2035.



### Background

Declining TAPS throughput TAPS is an 800-mile crude oil pipeline that transpo rts North Slope oil production south to the Alyeskamarine terminal in Valdez, Alaska. The crude oil is then transported b y tankers to West Coast refineries. TAPS currently is the only means for transporting North Slope crude oil to refineries an d the petroleum consumption markets they serve.

From 2004 through 2006, Alyeska reconfigured and re furbished TAPS, spending about $400 million to $500 million [91] both to reduce operating expenses and to permit TAPS to operate at lower flow rates, with a potential minim um mechanical throughput rate thought to be about 200,000 barrels per day at that time [92]. As North Slope oil prod uction has declined, however, concern about TAPS operation under low flo w conditions has grown [93]. In August 2008, Alyesk a initiated its Low Flow Impact Study, which was released on June 15, 2 011 [94].

The Alyeska study identified the following potentia l problems that might occur as TAPS throughput decl ines from the current production levels:

 Water dropout from the crude oil, which could cause pipeline corrosion

 Ice formation in the pipe if the oil temperature dr ops below freezing

 Wax precipitation and deposition

 Soil heaving.

Other potential operational issues at low flow rate s include sludge dropout, reduced ability to remove wax, reduction in pipeline leak detection efficiency, pipeline shutdo wn and restart, and the running of pipeline pigs th at both clean the pipeline and check its integrity.
Although TAPS low flow problems could begin at volu mes around 550,000 barrels per day in the absence o f any mitigation, their severity is expected to increase as throughpu t declines further. As the types and severity of pr oblems multiply, the investment required to mitigate these is expected t o increase significantly. Because of the many and d iverse operational problems expected to occur at throughput volumes be low 350,000 barrels per day, considerable investmen t could be required to keep the pipeline operational below tha t threshold. The Alyeska study does not provide anyestimates of what it might cost to keep the pipeline operational below e ither 550,000 or 350,000 barrels per day. Currently , Alyeska is conducting tests and analyses to determine the likely efficacyand costs of different remedies.



### Mitigating the decline of North Slope oil productio n Although much of the public focus has been on the o perational capability of TAPS at low flow rates, th e more fundamental issue is declining oil production. The TAPS low flo w issue would be alleviated most readily by discove ry and production of large new sources of oil on the North Slope. Potent ial sources of significant North Slope oil producti on are located offshore in the Chukchi and Beaufort Seas and onshore in shale and heavy oil deposits. The Arctic National Wildlif e Refuge (ANWR) is also estimated to hold approximately 10.4 billion b arrels of technically recoverable oil resources, bu t Federal oil and gas leasing in ANWR currently is prohibited [ 95 ]. Another potential source of new TAPS volumes wou ld be the conversion of North Slope natural gas resources to either methano l or Fischer-Tropsch petroleum products that could be transported to market via TAPS. Finally, in the absence of new North Slope petroleum supplies, alternative crude oil transportation facilities could be developed, such as a new small diameter pi peline running parallel to the TAPS route [ 96 ] or a new offshore oil terminal for North Slope production.

Which of these potential low-flow solutions (or com bination thereof) may ultimately come to fruition is imposs ible to determine at this time. Moreover, each solution comes with it s own unique set of costs, risks, and lead times. N ot only does each solution entail its own set of risks, there is also a significant risk that production from existing N orth Slope fields might decline 

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8/9/2012 http://www.eia.gov/forecasts/aeo/IF_all.cfmmuch faster than anticipated and/or that the cost o f operating those fields might escalate much fasterthan expected. Under

those circumstances, there is a risk that any solut ion(s) could be both too little and too late, because the North Slope oil fields would be shut down before a TAPS solution could be implemented.
How quickly TAPS flows will decline, the types of l ow flow problems that might develop, and the degree of mitigation required depend on the success or failure of current offshor e and onshore oil exploration and development progr ams and the quality of the oil produced. For example, low-viscosity oil is less problematic to TAPS operations than heavy, viscous oil. Because the future success of North Slope oil exploration a nd development is unknown, it is prudent to conside r the circumstances under which North Slope oil production might cease altogether, causing a shutdown of the TAPS pipeline

. Aside from the question of what it might cost to ke ep TAPS operating at lower flow rates, an additiona l question is what it might cost to keep the existing North Slope oil fie lds producing. Even if the continued operation of T APS were not in question, each North Slope oil field's production w ill eventually decline to a point at which it is no longer economical to keep the field operating. Oil and gas fields typically a re shut down and abandoned when operating and maint enance costs exceed production revenues. At that point, wells are plugg ed and abandoned, surface equipment is removed, and the land is remediated to meet State and Federal requirements.
Although the cost structure of North Slope field pr oduction as production declines is unknown, product ion generally can be sustained profitably at lower production rates when oil prices are higher. Similarly, the economic fea sibility of mitigating the problems arising from TAPS low flow rates improves when oil prices are higher. Consequently, revenues generated by North Slope oil production will play a pivotal role in de termining the continued economic viability of exist ing North Slope oil fields, the development of new oil fields, the continued op eration of TAPS at lower flow rates, and the potent ial development of new transportation facilities.
Several basic strategies have been employed to miti gate declining oil production and revenues from exi sting oil fields. First, the field operator can drill in-fill wells into tho se portions of the reservoir where oil cannot flow to existing production wells. Second, the operator can use enhanced oil recovery (EOR) that involves injecting steam or gases (along with water) to reduce viscosity and increase oil volumes as an aid to moving oil to the production wells. Currently, methane and natural gas liquids are being reinjected with water into many N orth Slope oil fields to achieve this outcome, whic h is referred to as "miscible hydrocarbon" EOR [ 97 ].
Drilling in-fill and EOR injection wells requires i nvestments that are paid for through "maintenance" capital expenditures [ 98 ]. Both activities provide diminishing returns over ti me, as less oil typically is recovered with each ne w in-fill or EOR well, causing the cost per barrel of oil recovered to ris e over time. Table 13 shows the number of in-fill and gas/water injectio n wells completed in 2010 at the three largest North Slope oil fields.
The diminishing returns from new in-fill and EOR we lls is demonstrated in recent remarks by a ConocoPh illips official who noted that approximately $630 million was to be spe nt on maintenance capital expenditures in 2011, com pared with about $240 million in 2001 [ 99 ]. In 2001 and 2010, ConocoPhillips provided 37.4 p ercent and 39.1 percent, respectively, of total North Slope oil production [ 100 ]. Using those percentages to scale up ConocoPhilli ps maintenance capital expenditures so that they represent total capital expenditures for North Slope maintenance, then total North Slope mai ntenance costs can be estimated at about $640 million in 2001 and $1.6 bi llion in 2011—a 150-percent increase over a period in which total North Slope oil production declined from 931,000 barrels per day to 562,000 barrels per day. If maintenance capital expenditures increased at the same rate (150 percent) over the n ext 10 years, they could be as high as $4 billion i n 2021.
Another method for extending oil production is to p roduce increasing amounts of water relative to oil [ 101 ]. As oil is produced from a reservoir, water typically enters the format ion, causing the water-to-oil ratio to increase exp onentially over time as oil production volumes decline [ 102 ]. Because the cost per barrel for handling and rei njecting reservoir water typically is relatively constant, the operating cost per barrel of oil produced increases exponentially over time.



### Shutdown and abandonment assumptions 

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8/9/2012 http://www.eia.gov/forecasts/aeo/IF_all.cfmAccording to the Alyeska study, a TAPS throughput o f about 350,000 barrels per day appears to be the t hreshold at which

significant investment would be required to permit lower TAPS throughput. AEO2012 adopts the 350,000 barrel per day figure as the threshold for either making significa nt investments in TAPS or the alternatives, or shut ting down and decommissioning TAPS and the North Slope oil fields [ 103 ].

In the AEO2012

analysis, the shutdown and decommissioning of TAPS and the North Slope oil fields are also conditiona l on whether North Slope wellhead oil production revenue s fall below a specific level. The appropriate revenue threshold is uncertain, because there is little or no informatio n available to the public on operating and maintena nce costs for existing oil fields, how those costs have grown historically as production has declined, or how they might grow in the future. Similarly, there are no public data available on what it mightcost to keep TAPS operating as throughput declines [ 104 ]. Given the lack of public information, this analysis endeavors to d etermine both future North Slope production revenues in alternative oil price cases and an order-ofmagnitude estimate of wellhead production costs.

AEO2012

assumes that, in order for the North Slope fields to be shut down, plugged, and abandoned, two condit ions would need to be met simultaneously: TAPS throughput at o r below 350,000 barrels per day and total North Slo pe oil production revenues at or below $5 billion per year. It is als o assumed that if those two conditions were met, TA PS would be decommissioned and dismantled, and North Slope oil exploration and production activities would cease [ 105 ].
The $5 billion threshold for North Slope oil produc tion revenue used in AEO2012 is not intended to be conclusive regarding the conditions under which the North Slope oil fiel ds and TAPS would remain in operation. As noted ear lier, in-fill and EOR well drilling requirements could escalate to about $4 b illion per year by 2021 [ 106 ]. Moreover, with the State of Alaska royalty rate currently at about 18.5 percent [ 107 ], a $5 billion revenue level would equate to almos t $1 billion in royalties.

Also, an order of magnitude estimate of operating c osts can be made by examining what oil companies re port for their annual production expenses. For example, ExxonMobil report ed a range of regional production costs per barrel of oil equivalent (excluding taxes) of $6.17 to $20.07 per barrel in 2010, with the U.S. average production cost being $ 10.67 per barrel [ 108 ]. At 350,000 barrels per day, a North Slope operating expense of $10 to $20 per barrel would equate to $ 1.28 to $2.56 billion per year in annual operating expenses. Of course, p roduction costs could well exceed $20 per barrel as North Slope oil production declines.
Although the $5 billion North Slope revenue figure is not conclusive with regard to the actual annual costs faced by North Slope field operators in the future, it is a reason able estimate in light of the sum of current mainte nance capital expenditures ($1.6 billion), estimated operating expenses at 350 ,000 barrels per day ($1.28 to $2.56 billion), and a royalty cost of about $1 billion. As discussed below, the oil production rev enue threshold serves to either advance or delay th e date when TAPS and North Slope oil production would be shut down.

The final assumption is that a complete shutdown ofNorth Slope oil production would occur in the yearin which both the throughput and revenue criteria are satisfied. In r eality, the actual shutdown of North Slope oil prod uction might be extended over a number of years and could begin either befor e or after the year in which the criteria employed by North Slope producers are met.



### Projections

figure data
A shutdown of North Slope oil production before 203 5 is projected only in the Low Oil Price case, which sho ws both TAPS throughput and North Slope oil revenues falling below the 350,000 barrels per day and $5 bi llion per year thresholds, respectively, in 2026 (Figures 52 and 53). In both the Reference and High Oil Price cases , oil 

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8/9/2012 http://www.eia.gov/forecasts/aeo/IF_all.cfmprices are sufficiently high both to stimulate the

development of new North Slope oil fields, especial ly offshore, and to provide sufficient oil producti on revenues to keep the North Slope producing oil through 2035.

figure data
Figure 53 shows the projected North Slope oil produ ction revenue stream over time in the three price cases, with North Slope oil production continuing even after production volume and revenue requirements are no longer met in the Low Oil Price case. Thus, if the minimum North Slope revenue requirement were $7.5 billion, a shutdown of North Slope production could occur as soon as 2020, but only in the Low Oil Price case

. There is considerable uncertainty about the long-te rm viability of North Slope oil production and continu ed operation of TAPS through 2035. The two most import ant determinants of their future viability are the well head oil price that North Slope producers receive and the availability and cost of developing new North Slope oil resources. Those two factors will determine whethernew oil fields are developed, whether existing oil fiel ds remain sufficiently profitable to continue opera ting, and whether the investments required to keep TAPS operating at flowrates below 350,000 barrels per day are economical ly feasible.

The AEO2012

Low and High Oil Price cases suggest that North Sl ope oil production will remain viable across a wide range of oil prices. Only in the Low Oil Price case are N orth Slope wellhead oil revenues sufficiently low t o cause a shutdown of North Slope oil production. If the Low Oil Price ca se represents a low-probability outer boundary for future oil prices, then the likely future outcome is that North Slope oil produ ction will continue until at least 2035, if not lon ger.


## 11. U.S. crude oil and natural gas resource uncertainty A common measure of the long-term viability of U.S. domestic crude oil and natural gas as an energy source is t he remaining technically recoverable resource (TRR). Estimates o f TRR are highly uncertain, however, particularly i n emerging plays where few wells have been drilled. Earlyestimates tend to vary and shift significantly ove r time as new geological information is gained through additional drilling, as long-term productivity is clarified for existing wells, and as the productivity of new wells increases with technology improvements and better managementpractices. TRR estimates used by EIA for each AEO are based on the latest available well production d ata and on information from other Federal and State governmental agencies, industry, and academia.

The remaining TRR consist of "proved reserves" and "unproved resources." Proved reserves of crude oil and natural gas are the estimated volumes expected to be produced, with reasonable certainty, under existing economic and operating conditions [ 109 ]. Proved reserves are also company financial asset s reported to investors, as determined by U.S. Secu rities and Exchange Commission regulations. Unproved resou rces are additional volumes estimated to be technic ally recoverable without consideration of economics or operating conditions, based on the application of current te chnology [ 110 ]. As wells are drilled and field equipment is installed, unpro ved resources become proved reserves and, ultimatel y, production.
AEO estimates of TRR for shale gas and tight oil [ 111 ] have changed significantly in recent years ( Table 14 ) [ 112 ]. In particular, the estimates of shale gas TRRs have ch anged significantly since the AEO2011 was published, based on new well performance data and United States Geological Survey (USGS) resource assessments. For example, in the past year the USGS has released resource assessments for five basins: Appalachian (Marcellus only), Arkoma, Texa s-Louisiana

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8/9/2012 http://www.eia.gov/forecasts/aeo/IF_all.cfmMississippi Salt, Western Gulf, and Anadarko [ 113 ]. The shale gas and tight oil formations in those five basins were the

primary focus of EIA's resource revisions for AEO2012 . In 2002, the USGS estimated Marcellus TRR at 1.9 trillion cubic feet; in 2011, the updated USGS estimate for Marcellus wa s 84 trillion cubic feet (see the following article for more discussion). For the four other basins, shale gas and tight oil TRR had not been assessed previously. The USGS has not published an assessment of the Utica play in the Appalachian Bas in.

The remainder of this discussion describes how esti mates of remaining U.S. unproved technically recove rable resources of shale gas and tight oil are developed for AEO , and how uncertainty in those estimates could affe ct U.S. crude oil and natural gas markets in the future.

The remaining unproved TRR for a continuous-type sh ale gas or tight oil area is the product of (1) lan d area, (2) well spacing (wells per square mile), (3) percentage of area unt ested, (4) percentage of area with potential, and ( 5) EUR per well [ 114 ]. The USGS periodically publishes shale gas resource assessments that are used as a guide for selection of key parameters in the calculation of the TRR used in the AEO . The USGS seeks to assess the recoverability of sh ale gas and tight oil based on the wells drilled and technologies deployed at t he time of the assessment.

The AEO

TRRs incorporate current drilling, completion, and recovery techniques, requiring adjustments to the USGS estimates, as well as the inclusion of shale gas an d tight oil resources not yet assessed by USGS. Whe n USGS assessments and underlying data become publicly ava ilable, the USGS assumptions for land area, well sp acing, and percentage of area with potential typically are use d by EIA to develop the AEO TRR estimates. EIA may revise the well spacing assumptions in future AEOs to reflect evolv ing drilling practices. If well production data are available, EIA analyzes the decline curve of producing wells to calculate t he expected EUR per well from future drilling.
Of the five basins recently assessed by the USGS, u nderlying details have been published only for the Marcellus shale play in the Appalachian basin. AEO2012 assumptions for the other shale plays are based on geologic surveys provided from State agencies (if available), analysis of availabl e production data, and analogs from current produci ng plays with similar geologic properties ( Table 15 ). For AEO2012 , only eight plays are included in the tight oil ca tegory ( Table 16 ). Additional tight oil resources are expected to be included in the ti ght oil category in future AEO s as more work is completed in identifying currently producing reservoirs that may be categori zed as tight formations, and as new tight oil plays are identified and incorporated.

A key assumption in evaluating the expected profita bility of drilling a well is the EUR of the well. E URs vary widely not only across plays but also within a single play. To capt ure the economics of developing each play, the unpr oved resources for each play within each basin are divided into subpla ys—first across States (if applicable), and then in to three productivity categories: best, average, and below average. Altho ugh the average EUR per well for a play may not cha nge by much from

one AEO

to the next, the range of well performance encompa ssed by representative EURs can change substantiall y ( Table 17 ).

For every AEO , the EUR for each subplay is determined by fitting a hyperbolic decline curve to the latest productio n history, so that changes in average well performance can be captured. Annual reevaluations are particularly imp ortant for shale gas and tight oil formations that have undergone rapid development. For example, because there has been a dramatic change from drilling vertical wells to drilling horizontal wells in most tight oil and shale gas plays since 2003, EURs for those plays based on vertical well performance are less useful for estimating production from future drilling, given that most new wells are expected to be primarily horizontal.

figure data

In addition, the shape of the annual well productio n profiles associated with the EUR varies substantial ly across the plays (Figure 54). For example, in the Marcellus, Fayetteville, and Woodford shale gas pla ys, 

## Page 45 of 55 U.S. Energy Information Administration (EIA)

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8/9/2012 http://www.eia.gov/forecasts/aeo/IF_all.cfmnearly 65 percent of the well EUR is produced in th e first 4 years. In contrast, in the Haynesville an d Eagle Ford plays, 95

percent and 82 percent, respectively, of the well E UR is produced in the first four years. For a given EUR level, increased "front loading" of the production profile improves well economics, but it also implies an increased ne ed for additional drilling to maintain production levels.

At the beginning of a shale play's development, hig h initial well production rates result in significa nt production growth as drilling activity in the play increases. The length of time over which the rapid growth can be sustain ed depends on the size of the technically recoverable resource in each play, the rate at which drilling activity increases, and the extent of the play's "sweet spot" area [ 115 ]. In the longer term, production growth tapers offas high initial production rates of new wells in "swe et spots" are offset by declining rates of existing we lls, and as drilling activity moves into less-produ ctive areas. As a result, in the later stages of a play's resource development, maintaining a stable production rate requires a sig nificant increase in drilling.

The amount of drilling that occurs each year depend s on company budgets and finances and the economics of drilling, completing, and operating a well—determined largelyby wellhead prices for oil and natural gas in the area. For example, current high crude oil prices and low natural gas p rices are directing drilling toward those plays or portions of plays with a high concentration of liquids (crude oil, condensat es, and natural gas plant liquids). Clearly, not al l the wells that would be needed to develop each play fully can be drilled in one year—for example, more than 630,000 new wells would be needed to bring total U.S. shale gas and tight oil resources into production. In 2010, roughly 37,500 total oil and natural gas wells were drilled in the United States. It takes time and mon ey to evaluate, develop, and produce hydrocarbon re sources.
Although changes in the overall TRR estimates are i mportant, the economics of developing the TRR and t he timing of the development determine the projections for productio n of domestic crude oil and natural gas. TRR adjust ments that affect resources which are not economical to develop durin g the projection period do not affect the AEO projections. Thus, significant variation in the overall TRR does not a lways result in significant changes in projected pr oduction.



### EUR sensitivity cases and results Estimated ultimate recovery per well is a key compo nent in estimates of both technically recoverable r esources and economically recoverable resources of tight oil and shale gas. The EUR for future wells is highly unce rtain, depending on the application of new and/or improved technologies as well as the geology of the formation where the well s will be drilled. EUR assumptions typically have more impact on projected production than do any of the other parameters use d to develop TRR estimates. For AEO2012, two cases were created to examine the impacts of higher and lower TRR for tight oil and shale gas by varying the assumed EUR per well.

These High and Low EUR cases are not intended to re present a confidence interval for the resource base , but rather to illustrate how different EUR assumptions can affectprojections of domestic production, prices, and co nsumption. To emphasize this point, an additional case was develo ped that combines a change in the assumed well spac ing for all shale gas and tight oil plays with the EUR assumptions in the High EUR case. Well spacing is also highly unc ertain, depending on the application of new and/or improved technologies as well as the geology of the formation where the well is being drilled. In the AEO2012

Reference case, the well spacing for shale gas and tight oil drilling ranges from 2 to 12 wells per s quare mile.

Low EUR case. In the Low EUR case, the EUR per tigh t oil or shale gas well is assumed to be 50 percent lower than in the Reference case, increasing the per-unit cost of dev eloping the resource. The total unproved tight oil TRR is decreased to 17 billion barrels, and the shale gas TRR is decreased to 241 trillion cubic feet, as compared with 33 bi llion barrels of tight oil and 482 trillion cubic feet of shale gas in the Ref erence case.
High EUR case. In the HIGH EUR case, the EUR per ti ght oil or shale gas well is assumed to be 50 perce nt higher than in the Reference case, decreasing the per-unit cost ofdeveloping the resource. The total unproved tight oil TRR is increased to 50 billion barrels and the shale gas TRR is increas ed to 723 trillion cubic feet.

High TRR case. In the High TRR case, the well spaci ng for all tight oil and shale gas plays is assumed to be 8 wells per 

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8/9/2012 http://www.eia.gov/forecasts/aeo/IF_all.cfmsquare mile (i.e., each well has an average drainag e area of 80 acres), and the EUR per tight oil or s hale gas well is

assumed to be 50 percent higher than in the Referen ce case. In addition, the total unproved tight oil TRR is increased to 89 billion barrels and the shale gas TRR is increased to 1,091 trillion cubic feet, more than twice the T RRs for tight oil and shale gas wells in the Reference case.

The effects of the changes in assumptions in the th ree cases on supply, demand, and prices for oil and for natural gas are significantly different in magnitude, because the d omestic oil and natural gas markets are distinctly different markets. Consequently, the following discussion focuses firs t on how the U.S. oil market is affected in the thr ee sensitivity cases, followed by a separate discussion of how the U.S. n atural gas market is affected in the three cases.



### Crude oil and natural gas liquid impacts The primary impact of the Low EUR, High EUR, and Hi gh TRR cases with respect to oil production is a ch ange in production of tight oil and natural gas plant liquids (NGPL) ( Table 18 ). NGPL production is discussed in conjunction with tight oil production, because significant volumes of NGPL are produced from tight oil and shale gas formations. Thus, changing the EURs directly affects NGPL production. Relative to the Reference case, tight oil production increases more slowly in the Low EUR case and more rapidly in the High EUR and High TRR cases. On average, tight oil production from 20 20 to 2035 is approximately 450,000 barrels per day lower in the Low EUR case, 410,000 barrels per day higher in the High EUR case, and 1.3 million barrels per day higher in the High TRR case than in the Reference case (Figure 55). NG PL production in 2035 is more than 350,000 barrels per day lower in the Low EUR case than in the Reference case, nearly320,000 barrels per day higher in the High EUR case, and 1.0 millio n barrels per day higher in the High TRR case.

figure data

Tight oil production is highest in the High TRR cas e, which assumes both higher EUR per well and generall y lower drainage area per well than in the Reference case. In the High TRR case, tight oil production increase s from roughly 400,000 barrels per day in 2010 to nearly 2 .8 million barrels per day in 2035, with the Bakken formation accounting for most of the increase. The TRR estima te for the Bakken is more than 7 times higher in the H igh TRR case than in the Reference case—39.3 billion barrels compared to 5.4 billion barrels—which suppo rts a continued dramatic production increase through 2015 and a longer plateau at a much higher production le vel through 2035 than in the Reference case. Bakken cru de oil production (excluding NGPLs) increases from rou ghly 270,000 barrels per day in 2010 to nearly 800,000 barrels per day in 2015 before reaching over 1 million barrels per day in 2021 and remaining at that level through 203 5 in the High TRR case, compared with peak tight oi l production of roughly 530,000 barrels per day in the Reference ca se. Cumulative crude oil production from the Bakken from 2010 to 2035 is roughly 8.5 billion barrels in the High TRR case , compared with 4.3 billion barrels in the Referenc e case.
Every incremental barrel of domestic crude oil prod uction displaces approximately one barrel of import s, because U.S. consumption of liquid fuels varies little across th e cases. Consequently, the projected share of net p etroleum imports in total U.S. liquid fuel consumption in 2035 varies conside rably across the EUR and TRR cases, from 41 percentin the Low EUR case to 24 percent in the High TRR case, as compare d with 36 percent in the Reference case. However, a dditional downstream infrastructure may be required to proces s the high levels of NGPL production in the High EU R and High TRR

cases. 

## Page 47 of 55 U.S. Energy Information Administration (EIA)

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8/9/2012 http://www.eia.gov/forecasts/aeo/IF_all.cfmChanges in domestic oil production have only a mode st impact on domestic crude oil and petroleum produ ct prices, because

any change in domestic oil production is diluted bythe much larger world oil market. The United State s produced 5.5 million barrels per day, or 7 percent of total world crude oil production of 73.9 million barrels per day in 2 010 and is projected generally to maintain that share of world crude oil production through 2035 in the Reference case.



### Natural gas impacts The EUR and TRR cases show more significant impacts on U.S. natural gas supply, consumption, and price s than that projected for crude oil and petroleum products for two reasons ( Table 19 ). First, the U.S. natural gas market constitutes t he largest regional submarket within the relatively se lf-contained North American natural gas market. Sec ond, in the Reference case, shale gas production accounts for 49 percent of total U.S. natural gas production in 2035, while tight oil production accounts for only 14 percent of total U.S. crude oi l and NGPL production and 1 percent of world crude oil production. As a result, changes in shale gas production have a comm ensurately larger impact on North American natural gas prices than tight oil production has on world oil prices.

figure data

The projections for domestic shale gas production a re highly sensitive to the assumed EUR per well. In 20 35, total shale gas production varies from 9.7 trillion cubic feet in the Low EUR case to 16.0 trillion cubic fee t in the High EUR case and 20.5 trillion cubic feet in the H igh TRR case, as compared with 13.6 trillion cubic feetin the Reference case (Figure 56). Because shale gas production accounts for such a large proportion of total natural gas production in 2035, the large changes i n shale gas production result in commensurately large swings in total U.S. natural gas production. In 203 5, total U.S. natural gas production ranges from 26.1 trilli on cubic feet in the Low EUR case to 34.1 trillion cubic fee t in the High TRR case, a difference of 8.0 trillion cubic f eet production between the two cases.

In comparison with the Reference case, per-unit pro duction costs are nearly double in the Low EUR case and about one-half in the High EUR case. In the Low EUR case, the Henr y Hub natural gas price of $8.26 per million Btu in 2035 (2010 dollars) is $0.89 per million Btu higher than the Reference case price of $7.37 per million Btu. In the High EU R case, the 2035 Henry Hub natural gas price of $5.99 per million Btu is $ 1.38 per million Btu lower than the Reference case price. In the High TRR case, the 2035 Henry Hub natural gas price of $4.25 per million Btu is $3.12 per million Btu less than the Reference case price.

The natural gas prices projected in the Low EUR cas e are sufficiently high to enable completion of an Alaska gas pipeline, with operations beginning in 2031. Because an Alaska ga s pipeline would make up for some of the reduction in Lower 48 shale gas production, differences between the Refer ence and Low EUR case projections for natural gas p roduction, prices, and consumption in 2035 are somewhat less than woul d otherwise be expected.
The 2035 price spread of $4.01 per million Btu acro ss the cases is reflected in the projected levels o f U.S. natural gas consumption. Higher natural gas prices in the Low E UR case reduce total natural gas consumption to 25. 0 trillion cubic feet in 2035, compared with 26.6 trillion cubic feet in the Reference case; and lower natural gas prices in the High EUR and High TRR cases increase consumption in 2035 to 28.4 tril lion cubic feet and 31.9 trillion cubic feet, respe ctively.
The variation in total U.S. natural gas consumption between the High EUR and High TRR cases is reflect ed to some degree 

## Page 48 of 55 U.S. Energy Information Administration (EIA)

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8/9/2012 http://www.eia.gov/forecasts/aeo/IF_all.cfmin each end-use category. The electric power sectorshows the greatest sensitivity to natural gas pric es, with natural gas use

for electricity generation being more responsive to changes in fuel prices than is consumption in the other sectors, because much of the electric power sector's fuel consumptio n is determined by the dispatching of existing gene ration units based on the operating cost of each unit, which in turn is d etermined largely by the costs of competing fuels—e specially coal and natural gas. Natural gas consumption in the electri c power sector in 2035 totals 7.7 trillion cubic fe et in the Low EUR case, compared with 9.0 trillion cubic feet in the Refere nce case, 10.1 trillion cubic feet in the High EUR case, and 12.6 trillion cubic feet in the High TRR case.

In the end-use consumption sectors, opportunities t o switch fuels generally are limited to when a new facility is built or when a facility's existing equipment is retired and repl aced. Collectively, for all the end-use sectors, na tural gas consumption in 2035 varies by only about 1.9 trillion cubic feet a cross the cases, from 17.3 trillion cubic feet in t he Low EUR case to 19.2 trillion cubic feet in the High TRR case, as compar ed with 17.7 trillion cubic feet in the Reference c ase.
In 2035, the United States is projected to be a netexporter of natural gas in all the cases. The proj ected volumes of net exports vary, with lower natural gas prices resulti ng in higher net exports. However, the High TRR, Hi gh EUR, and Low EUR cases assume that U.S. gross exports of LNG remain constant at 0.9 trillion cubic feet from 2020 throu gh 2035, because of the inherent complexities and uncertainties of proj ecting foreign natural gas production, consumption, and trade. It is likely, however, that actual levels of net LNG exports woul d be affected by changes in U.S. prices, which in t urn, would dampen the extent of the price difference across the resource cases.
The variation in levels of net U.S. natural gas exp orts shown in Table 20 reflects the impact of domestic natural gas prices on natural gas pipeline imports and exports. Generally , lower natural gas prices, as in the High TRR case, result in lower n atural gas imports from Canada and higher natural gas expo rts to Mexico. In 2035, net natural gas exports fro m the United States vary from 1.2 trillion cubic feet in the Low EUR ca se to 2.4 trillion cubic feet in the High TRR case, as compared with 1.4 trillion cubic feet in the Reference case.

The sensitivity cases in this discussion are not in tended to provide a confidence interval for estimat es of recoverable resources of domestic tight oil and shale gas but r ather to illustrate the significance of key assumpt ions underlying the tight oil and shale gas TRRs used in AEO2012 . TRR estimates are highly uncertain and can be exp ected to change in subsequent AEO s as additional information is gained through conti nued exploration, development, and production.


## 12. Evolving Marcellus shale gas resource estimates As discussed in the preceding article, estimates ofcrude oil and natural gas TRR are uncertain. Estim ates of the Marcellus shale TRR, which have received considerable attenti on over the past year, are no exception. TRR estima tes are likely to continue evolving as drilling continues and more in formation becomes publicly available. The Marcellus shale gas play covers more than 100,000 square miles in parts of e ight States, but most of the drilling to date has b een in two areas of northeast Pennsylvania and southwest Pennsylvania/n orthern West Virginia. Until 2010, the State of Pen nsylvania had maintained a 5-year embargo on the release of well- level production data, which severely limited the p ublicly available information about Marcellus well production. Now Pe nnsylvania provides well production data on a cumul ative basis— annually for the years before 2010 and semi-annuall y starting in the second half of 2010. Even with mo re data available, however, it is still a challenge to estimate TRR fo r the Marcellus play.

In 2002, the USGS estimated that 0.8 trillion cubicfeet to 3.7 trillion cubic feet of technically recoverable shale gas resources existed in the Marcellus, with a mean est imate of 1.9 trillion cubic feet [ 116 ]. At that time, most of the well production data available were for vertical we lls drilled in West Virginia. Since 2003, technologicalimprovements have led to more-productive and lesscostly wells. The newer horizontal wells have highe r 

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8/9/2012 http://www.eia.gov/forecasts/aeo/IF_all.cfmEURs [ 117 ] than the older vertical wells. In 2011, the

USGS released an updated assessment for the Marcell us resource, with a mean estimate of 84 trillion cu bic feet of undiscovered TRR (ranging from 43 trillion cubic fe et to 144 trillion cubic feet) [ 118 ]. For its 2011 assessment, the USGS evaluated well production data from Pennsylvania an d West Virginia that were available in early 2011 a nd determined that the data were "not sufficient for the construction of individual well Estimated Ultimate Recovery dist ributions" [ 119 ]. Instead, the USGS chose analogs from other U.S. shale gas pl ays to determine the EUR distributions for its thre e Marcellus assessment units—Foldbelt, Interior, and Western Ma rgin (Figure 57).
Estimates of the TRR for U.S. shale gas are updated each year for the AEO . For AEO2011 , an independent consultant was hired to estimate the Marcellus TRR as the availabl e USGS TRR estimate issued in 2003 was clearly too low, since cumulative production from the Marcellus shale was on a path to exceed it within a year or two. For AEO2012 , EIA adopted the 2011 USGS estimates of the Marcellus assessmentareas, well spacing, and percent of area with potential. However, EIA examines available well production data each year t o estimate shale EURs for use in the AEO (Table 20).

The revised Marcellus EUR for AEO2012 is close to t he EUR used in AEO2011 but nearly 70 percent higher than the EUR used in the 2011 USGS assessment. The Interior Asse ssment Unit EURs developed by EIA reflects the curr ent practice of horizontal drilling and well production data throug h June 2011 for Pennsylvania and West Virginia [ 120 ]. Because there has been very little, if any, drilling in the Western M argin and Foldbelt Assessment Units, the USGS EURs were used for the States in those areas. The resulting AEO2012 estimate for the Marcellus TRR is 67 percent lowerthan the AEO2011 estimate, primarily as a result of increased well s pacing (132 acres per well vs.80 acres per well) an d a lower percentage of area with potential (18 percent vs. 34 percent) ( Table 21 ).

The estimation of Marcellus shale gas resources is highly uncertain, given both the short production h istory of current producing wells and the concentration of most produ cing wells in two small areas, Northeast Pennsylvan ia and Southwest Pennsylvania/Northern West NC Virginia. The Marcell us EURs are expected to change as additional data a re released and the methodology for developing EURs is refined. Als o, as more wells are drilled over a broader area, a nd as operators optimize well spacing to account for evolving drill ing practices, the assumption for average well spac ing may be revised. Although the Marcellus shale resource estimate will be updated for every AEO , revisions will not necessarily have a significant impact on projected natural gas product ion, consumption, and prices.



## Endnotes for Issues in focus
41 Oil shale liquids, derived from heating kerogen, a re distinct from shale oil and also from tight oil, which is classified by EIA as crude oil. Oil shale is not expected to be produ ced in significant quantities in the United States before 2035.

42 U.S. Environmental Protection Agency and National Highway Transportation Safety Administration, " 2017 and Later Model Year Light-Duty Vehicle Greenhouse Gas Emissions an d Corporate Average Fuel Economy Standards; Propose d Rule ," Federal Register, Vol. 76, No. 231 (Washington, DC: December 1, 2011).

43 The EISA2007 RFS requirement for increasing volume s of biofuels results in a significant number of FF Vs in both the Reference case and the CAFE case.

44S. Bianco, " Chevy Volt Has Best Month Ever, But Nissan Leaf Sti ll Wins 2011 Plug-in Sales Contest ," autobloggreen.

45 Battery electric vehicle charge-depleting mode occ urs when the vehicle relies on battery power for op eration. Chargesustaining mode occurs when battery electric power is coupled with power provided by the interna l combustion engine. Vehicles can be designed to operate on a bl ended mode that uses both charge-depleting and char ge-sustaining modes while in operation, depending on the drive cy cle.

46 Toyota, "Toyota Cars, Trucks, SUVs, and Accessorie s," website www.toyota.com ; Nissan USA, "Nissan Cars, Trucks, Crossovers, & SUVs," website www.nissanusa.com; and Chevrolet, "2012 Cars, SUVs, Trucks, Crossovers & Vans," website www.chevy.com . Note: Miles per gallon equivalent, as listed by a utomotive manufacturers, is derived by the U.S. 

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8/9/2012 http://www.eia.gov/forecasts/aeo/IF_all.cfmEnvironmental Protection Agency, www.fueleconomy.gov

.

47 Toyota, "Toyota Cars, Trucks, SUVs, and Accessories ," website www.toyota.com ; Nissan USA, "Nissan Cars, Trucks, Crossovers, & SUVs," website www.nissanusa.com; and Chevrolet, "2012 Cars, SUVs, Trucks, Crossovers & Vans," website www.chevy.com . Note: Miles per gallon equivalent, as listed by a utomotive manufacturers, is derived by the U.S. Environmental Protection Agency, www.fueleconomy.gov

.

48 U.S. Department of Energy, Office of Energy Effici ency and Renewable Energy, " Vehicle Technologies Program ."

49 U.S. Energy Information Administration, " Residential Energy Consumption Survey (RECS), 2009 RECS Survey Data ."

50 U.S. Department of Energy, Office of Energy Effici ency and Renewable Energy, " Alternative Fuels & Advanced Vehicles Data Center ."

51 Indiana University, School of Public and Environme ntal Affairs, " Plug-in Electric Vehicles: A Practical Plan for Pro gress ."

52 U.S. Environmental Protection Agency and National Highway Transportation Safety Administration, " 2017 and Later Model Year Light-Duty Vehicle Greenhouse Gas Emissions an d Corporate Average Fuel Economy Standards; Propose d Rule ," Federal Register, Vol. 76, No. 231 (Washington, DC: December 1, 2011).

53 For this analysis, heavy-duty vehicles include tru cks with a Gross Vehicle Weight Rating of 10,001 po unds and higher, corresponding to Gross Vehicle Weight Rating classe s 3 through 8 vehicles.

54U.S. Department of Energy, Office of Energy Effici ency and Renewable Energy, " Alternative Fueling Station Database Custom Query " (Washington, DC: June 3, 2010). Accessed June 30, 2012.

55 National Petroleum News, Market Facts 2011.

56 U.S. Department of Energy, Office of Energy Effici ency and Renewable Energy, Clean Cities Alternative Fuel Price Report (Washington, DC: April, 2012).

57The Texas Clean Transportation Triangle is support ed by Texas State Senate Bill 20, which provides ve hicle rebates and fueling grants. See West, Williams, House Research Organization, " Bill Analysis: SB 20 " (Austin, TX: May 21, 2011).

58 The Interstate Clean Transportation Corridor was d eveloped in 1996. The corridor is now partially est ablished with LNG truck refueling infrastructure in California and to Reno, Las Vegas, and Phoenix. See Gladstein, Neand ross & Associates, "Interstate Clean Transportation Corridor" (Santa M onica, CA: February 2, 2012), website ictc.gladstein.org

.

59 The Pennsylvania Clean Transportation Corridor was proposed in a report, " A Road Map to a Natural Gas Vehicle Future " (Canonsburg, PA: April 5, 2011), sponsored by the Marcellus Shale Coalition.

60 The American Recovery and Reinvestment Act has pro vided more than $300 million toward cost-sharing pr ojects related to alternative fuels. U.S. Department of Energy, Of fice of Energy Efficiency and Renewable Energy, " American Recovery and Reinvestment Act Project Awards " (Washington, DC: September 7, 2011).

61 For a map of U.S. LNG peak shaving, see U.S. Energ y Information Administration, " U.S. LNG Peaking Shaving and Import Facilities, 2008 " (Washington, DC: December, 2008).

62 The LNG Excise Tax Equalization Act of 2012, propo sed in the U.S. House of Representatives, would req uire the tax treatment of LNG and diesel fuel to be equivalent o n the basis of heat content. See Civic Impulse, LLC , " H.R. 3832: LNG Excise Tax Equalization Act of 2012 " (Washington, DC: May 29, 2012).

63 Developed from e-mail correspondence with Graham W illiams, 4/11/12. 

## Page 51 of 55 U.S. Energy Information Administration (EIA)

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8/9/2012 http://www.eia.gov/forecasts/aeo/IF_all.cfm64U.S. Environmental Protection Agency and National Highway Transportation Safety Administration, " Greenhouse Gas

Emissions Standards and Fuel Efficiency Standards f or Medium- and Heavy-Duty Engines and Vehicles ," Federal Register Vol. 76, No. 179 (Washington, DC: September 15, 201 1).

65 U.S. Census Bureau, " Vehicle Inventory and Use Survey (VIUS) (discontinu ed after 2002) " (Washington, DC: May 29, 2012).

66 U.S. Environmental Protection Agency and National Highway Transportation Safety Administration, " Greenhouse Gas Emissions Standards and Fuel Efficiency Standards f or Medium- and Heavy-Duty Engines and Vehicles ," Federal Register Vol. 76, No. 179 (Washington, DC: September 15, 201 1).

67For information on the New Alternative Transportat ion to Give Americans Solutions Act of 2012, see Ci vic Impulse, LLC,

" H.R. 1380: New Alternative Transportation to Give A mericans Solutions Act of 2011 " (Washington, DC: May 29, 2012).

68 The liquid fuels production industry includes all participants involved in the production of liquid f uels: producers of feedstocks, petroleum- and nonpetroleum-based refin ed products and blendstocks, and liquid and non-liq uid end-use products.

69 U.S. Environmental Protection Agency, " Mercury and Air Toxics Standards " (Washington, DC: March 27, 2012).

70 U.S. Environmental Protection Agency, " Cross-State Air Pollution Rule (CSAPR) " (May 25, 2012).

71 Other components of variable cost include emission s control technology, waste disposal, and emissions allowance credits.

72 The AEO2012 Early Release Reference case was prepa red before the final MATS rule was issued and, ther efore, did not include MATS.

73 United States Court of Appeals for the District ofColumbia Circuit, " EME Homer City Generation, L.P., v. Environmental Protection Agency " (Washington, DC: December 30, 2011).

74U.S. Energy Information Administration, Electric P ower Annual 2010 (Washington, DC, November 2011), T able 3.10,

" Number and Capacity of Existing Fossil-Fuel team-El ectric Generators with Environmental Equipment, 199 1 through 2010 ." U.S. Environmental Protection Agency, Office of Enf orcement and Compliance Assurance, " The Environmental Protection Agency's Enforcement Response Policy for Use of Cle an Air Act Section 113(a) Administrative Orders in Relation to Electric Reliability and the Mercury and Air Toxics Standard " (Washington, DC: December 16, 011).

75 U.S. Environmental Protection Agency, Office of En forcement and Compliance Assurance, " The Environmental Protection Agency's Enforcement Response Policy for Use of Cle an Air Act Section 113(a) Administrative Orders in Relation to Electric Reliability and the Mercury and Air Toxics Standard " (Washington, DC: December 16, 2011) .

76 See Appendix F for a map of the EMM regions

.

77The EPA is proposing that new fossil-fuel-fired po wer plants begin meeting an output-based standard o f 1,000 pounds CO2 per megawatthour. See U.S. Environmental Protec tion Agency, " Carbon Pollution Standard for New Power Plants " (Washington, DC: May 23, 2012). Existing coal pla nts without CCS will not be able to meet that stand ard, and the proposed rule does not apply to plants already unde r construction. The EPA proposal is not included in AEO2012.

78 U.S. Energy Information Administration, Form EIA-860, "Annual Electric Generator Report" (Washington, DC: November 30, 2011).

79 U.S. Energy Information Administration, " Levelized Cost of New Generation Resources in the A nnual Energy Outlook 2012 " (Washington, DC: March 2012). 

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8/9/2012 http://www.eia.gov/forecasts/aeo/IF_all.cfm80 U.S. Energy Information Administration, " Assumptions to AEO2012 " (Washington, DC: June 2012), website

www.eia.gov/forecasts/aeo/assumptions.

81 U.S. Government Printing Office, " Energy Policy Act of 2005, Public Law 109-58, Title XVII—Incentives for Innovative Technologies " (Washington, DC: August 8, 2005).

82 U.S. Department of Energy, Loan Programs Office, " Loan Guarantee Program: Georgia Power Company " (Washington, DC: June 4, 2012).

83 U.S. Government Printing Office, " Energy Policy Act of 2005, Public Law 109-58, Title XVII—Incentives for Innovative Technologies, paras. 638, 988, and 1306 " (Washington, DC, August 2005).

84U.S. Energy Information Administration, Form EIA-860, "Annual Electric Generator Report."

85 Tennessee Valley Authority, " Integrated Resource Plan " (Knoxville, TN: March 2011).

86 U.S. Nuclear Regulatory Commission, " Status of License Renewal Applications and IndustryActivities: Completed Applications " (Washington, DC: May 22, 2012).

87U.S. Nuclear Regulatory Commission, " Status of License Renewal Applications and IndustryActivities: Completed Applications " (Washington, DC: May 22, 2012).

88 Electric Power Research Institute, " Long-Term Operations (QA) " (Palo Alto, CA: June 4, 2012).

89 International Forum for Reactor Aging Management ( IFRAM), " Inaugural Meeting of the International Forum for Re actor Aging Management (IFRAM) " (Colorado Springs, CO: August 5, 2011).

90 Alyeska Pipeline Service Company, " Low Flow Impact Study, Final Report " (Anchorage, AL: June 15, 2011).

91 Tim Bradner, " Alyeska Invests in New Methods to Extend Pipeline L ife ," Alaska Journal of Commerce (June 1, 2009).

92 U.S. Department of Energy, National Energy Technol ogy Laboratory, " Alaska North Slope Oil and Gas â€“ A Promising Future or an Area in Decline? (Addendum Report) ," DOE/NETL-2009/1385 (Washington, DC: April 8, 200 9), pp. 1-4 and 1-5. 93. Alan Bailey, " TAPS transitioning to a low flow future ," Petroleum News, Vol. 14, No. 29 (Anchorage, AK: July 19, 2009), subscription website

.

93 Alan Bailey, " TAPS transitioning to a low flow future ," Petroleum News, Vol. 14, No. 29 (Anchorage, AK: July 19, 2009), subscription website

.

94Alyeska Pipeline Service Company, " Low Flow Impact Study, Final Report " (Anchorage, AL: June 15, 2011).

95 U.S. Department of the Interior, U.S. Geological S urvey, " The Oil and Gas Resource Potential of the Arctic Na tional Wildlife Refuge 1002 Area, Alaska, Open File Report98-34 " (Washington, DC: May 1998); U.S. Geological Surve y, " Arctic National Wildlife Refuge, 1002 Area, Petroleum Asse ssment, 1998, Including Economic Analysis, USGS Fac t Sheet FS-028- 01 " (Washington, DC: April 2001); and David W. Housek necht and Kenneth J. Bird, " Oil and Gas Resources of the Arctic Alaska Petroleum Province ," U.S. Geological Survey Professional Paper 1732â€ “A (Washington, DC: October 31, 2006).

96 In 2004, BP commissioned a study that examined the possibility of building a 20-inch pipeline to Fair banks and using the Alaska railroad to transport the oil to Valdez, at an estimated cost of about $3 billion. Source: Alan Bailey, " A TAPS bottom line ," Petroleum News, Volume 17, Number 3 (Anchorage, AK: January 15, 2012).

97 The most common miscible gas EOR technique is to al ternate the injection of gas and water, referred to as wateralternating-gas or WAG. Source: Oil and Gas Journal , " Special Report: EOR/Heavy Oil Survey: 2010 worldwid e EOR 

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98 Capital expenditures can be split into two categor ies—maintenance and development—with development ex penditures allocated to the development of new fields that hav e not yet reached peak production.

99 Source for 2011 CP capital expenditures—Petroleum News, "Eagle Ford Could Nudge Alaska for COP" (May 8, 2011); source for 2001 CP capital expenditures—Petroleum N ews, "Sunrise or Sunset for ConocoPhillips in Alask a?" (October 27, 2002); source for 2001 and 2011 CP split in capital expenditures—Petroleum News, "Johansen: Urgency La cking on Throughput" (October 16, 2011).

100 These figures were derived from the CP ownership s hares of the Colville River, Kuparuk River, and Pru dhoe Bay field units and from the oil production reports of the Al aska Department of Natural Resources—Oil and Gas Di vision.

101 The volume of water produced relative to the volum e of oil produced is referred to as the "water cut. "

102 U.S. Geological Survey, Economics of Undiscovered Oil in Federal Lands on the National Petroleum Rese rve—Alaska, by Emil Attanasi, Open-File Report 03-44 (January 2 003), Figures A-2 (Alpine Field) and A-3 (Kuparuk F ield).

103 In fact, these decisions would have to be made som e time before the 350,000-barrel-per-day threshold is reached so they would be ready for implementation either priorto reaching the threshold or when that threshold i s reached.

104 The owners of TAPS and operators of the North Slop e fields might not know either at this junction what these future costs might be for both operating TAPS and the North Slop e fields as volumes decline; at best they have esti mates that might or might not turn out to be true.

105 The assumption that all North Slope exploration ac tivity would cease with the decommissioning of TAPS might not be entirely realistic because some offshore oil fields might be economic to develop using floating produc tion, storage, and offloading facilities (FPSO). This would be especia lly true in the Chukchi Sea, which has much less ofan ice pack problem during the winter than the Beaufort Sea.

106 Maintenance capital expenditures could also declin e if the field operators determined that drilling m ore wells was unprofitable.

107 Petroleum News, "Who Produces Crude Oil in Alaska? " Vol. 16, No. 43 (October 23, 2011).

108 ExxonMobil, 2010 Financial & Operating Review, Tab le entitled: "Oil and Gas Exploration and Productio n Earnings," p. 70.

109 See also EIA, " U.S. Crude Oil, Natural Gas, and Natural Gas Liquid s Reserves ," November 30, 2010.

110 The further delineation of unproved resources into inferred reserves and undiscovered resources is no t applicable to continuous resources since the extent of the format ion is geologically known. For continuous resources , the USGS undiscovered technically recoverable resources are comparable to the EIA unproved resources. The USGS methodology for assessing continuous petroleum resources is at pubs.usgs.gov/ds/547/downloads/DS547.pdf

.

111 "Tight oil" refers to crude oil and condensates pr oduced from low-permeability sandstone, carbonate, and shale formations.

112 See shale gas map for basin locations.

113 Appalachian ; Arkoma ; TX-LA-MS Salt and Western Gulf ; Anadarko

.

114 A well's estimated ultimate recovery (EUR) equals the cumulative production of that well over a 30-ye ar productive life, 

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115 "Sweet spot" is an industry term for those select and limited areas within a shale or tight play wher e the well EURs are significantly greater than the rest of the play, so metimes as much as ten times greater than the lowerproduction areas within a play.

116 USGS Fact Sheet FS-009-03

.

117 A well's EUR equals the cumulative production of t hat well over a 30-year productive life, using curr ent technology without consideration of economic or operating conditions.

118 USGS Fact Sheet 2011-3092

.

119 USGS Open-File Report 2011-1298 , page 2.

120 Well-level production from Pennsylvania is provide d in two time intervals (annual and semi-annual). T o estimate production on a comparable basis, well-level produc tion is converted to an average daily rate by divid ing gas quantity by gas production days. Because wells drilled before 2008 are vertical wells and do not reflect the technolog y currently being deployed, only wells drilled after 2007 are conside red in the EUR evaluation. Well-level production fo r wells drilled in West Virginia is provided on a monthly basis. 

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