To provide a basis against which alternative cases and policies can be compared, the AEO2009 reference case generally assumes that current laws and regulations affecting the energy sector remain unchanged throughout the projection. This year’s reference case reflects recent changes in law—including the expiration of moratoria on offshore leasing in the Atlantic, Pacific, and Eastern Gulf of Mexico areas of the Outer Continental Shelf (OCS) and provisions in Public Law 110-343, the Energy Improvement and Extension Act of 2008 (EIEA2008), related to production and investment tax credits for renewable energy and designated energy equipment, such as plug-in hybrid electric vehicles (PHEVs)—as well as regulatory changes.¹

Other key changes in the AEO2009 projections include:

• Higher projections for delivered energy prices, reflecting both higher wellhead and minemouth prices and higher costs to transport, distribute, and refine fuels per unit supplied

• Revised capital costs for capital-intensive projects to reflect recent sharp increases in those costs

• Revised handling of hybrid vehicles, including PHEVs

• Recognition of the impact of uncertainty about greenhouse gas (GHG) legislation on investment decisions (see discussion on "Energy Investment Behavior: Impact of Concerns Over Greenhouse Gas Emissions")

• Updated characterization of unconventional natural gas production, in particular for natural gas shales.

Energy companies currently are operating in a challenging environment. Beyond the well-known uncertainties with respect to future demand growth and fuel, labor, and new plant costs, they also must consider the potential impact of concerns surrounding energy-related GHG emissions. Even without the enactment of Federal laws and policies limiting U.S. GHG emissions, regulators and the investment community are beginning to push energy companies to shift their investments towards less GH-Gintensive technologies.

For example, many State public utility commissions are requiring that the utilities they regulate prepare simulations in their integrated resource plans that include assumed carbon dioxide (CO2) allowance fees. The utilities often prepare a range of cases, with CO2 fees ranging widely from $0 to $80 per ton of CO2 or more. In addition, a number of major financial institutions (e.g., Citicorp, JPMorgan Chase, and Morgan Stanley) have adopted “carbon principles” under which they agree to “(1) encourage their clients to pursue cost-effective energy efficiency, renewable energy, and other low-carbon alternatives to conventional generation, taking into consideration the potential value of avoided CO2 emissions; (2) ascertain and evaluate the financial and operational risk to fossil fuel generation financings posed by the prospect of domestic CO2 emissions controls through the application of an ‘Enhanced Diligence Process,’a and use the results of this diligence as a factor in determining whether a transaction is eligible for financing and under what terms; and (3) educate clients, regulators, and other industry participants regarding the additional diligence required for fossil fuel generation financings, and encourage regulatory and legislative changes consistent with the Principles.” b

There are two key questions: to what extent are concerns about climate change already affecting operating and investment decisions in energy markets, and how should these impacts be represented in AEO2009? Although it appears that existing assets continue to be operated without adjustments for their GHG characteristics, there is considerable evidence that investors and regulators reviewing proposals for new power plants are considering GHG emissions in their investment evaluation process by implicitly (or explicitly) adding a cost to some plants, particularly those that involve GHG-intensive technologies.

To reflect this behavior, the AEO2009 reference case adds a 3-percentage point increase in the cost of capital when evaluating investments in GHG-intensive technologies, such as coal-fired power plants without carbon control and sequestration (CCS) and coal-to-liquids (CTL) plants. While the 3-percentage adjustment is somewhat arbitrary, in levelized cost terms its impact is similar to that of a $15-per-ton value for CO2 emissions when investing in a new coal plant without CCS, well within the range of the results of simulations that utilities and regulators have prepared. The adjustment should not be seen as an increase in the actual cost of financing but rather as representing an implicit hurdle being added to GHG-intensive projects to account for the possibility that eventually they may be required to purchase allowances or invest in other GHG-emission-reducing projects to offset their emissions.

In previous AEOs the reference cases did not incorporate such an adjustment. Investment decisions in those reference cases were treated in the same way as they would be in a world where the issue of climate change and the role of GHG emissions as a contributing factor did not exist. Current evidence suggests that such a methodology is now inappropriate to reflect business-as-usual behavior under current laws and regulations. To facilitate comparisons with previous AEOs, and to provide a measure of the impact of the change in methodology, the complete AEO2009 will also include an alternative case that does not incorporate the new financing adjustment
factor for long-lived investments in GHG-intensive technologies.

aAn expanded due diligence process that considers the probable risks posed by the costs of CO2 emissions and seeks to address those risks in financing decisions.
bSee Morgan Stanley, “Leading Wall Street Banks Establish The Carbon Principles” (Press Release, February 4, 2008), web site www.morganstanley.com/about/press/articles/6017.html.

Although world oil prices declined sharply at the end of 2008 with the slowing of the U.S. and world economies, the AEO2009 reference case includes higher world oil prices by 2030, based on a reevaluation of long-term fundamentals that support higher prices than expected in earlier AEOs. Prices begin to rise in 2010 (see Figure 1 on right) as the economy rebounds and global demand is expected to once again grow more rapidly than liquids supplies from producers outside the Organization of the Petroleum Exporting Countries (OPEC). In 2030, the average real price of crude oil in the reference case is $130 per barrel in 2007 dollars, or about $189 per barrel in nominal dollars. Alternative AEO2009 cases address higher and lower world crude oil prices.

The AEO2009 reference case assumes that access limitations restrain the growth of non-OPEC conventional liquids production between 2007 and 2030, and that OPEC targets a relatively constant market share of about 40 percent of total world liquids production.

Contributing to world oil price uncertainty is the degree to which non-OPEC countries and countries outside the Organization for Economic Cooperation and Development (OECD), such as Russia, restrict economic access to potentially productive resources. Other uncertain factors, including OPEC investment decisions, will affect the world oil price and the economic viability of unconventional liquids.

The AEO2009 reference case also includes significant long-term potential for supply from non-OPEC producers. In several resource-rich regions (including Brazil, Azerbaijan, and Kazakhstan), high oil prices, expanded infrastructure, and new exploration and drilling technologies contribute additional non-OPEC oil production. Also, with the economic viability of Canada’s oil sands enhanced by higher world oil prices and advances in production technology, oil sands production reaches 4 million barrels per day in 2030.

Real prices (in 2007 dollars) for motor gasoline and diesel in the AEO2009 reference case are $3.90 per gallon and $3.91 per gallon in 2030—$1.39 and $1.16 per gallon higher, respectively, than in the AEO2008 reference case, largely as a result of higher crude oil prices. Despite being almost equal in 2030, diesel prices generally are higher than gasoline prices throughout the projection because of continued strong growth in world demand.

Retail prices for E85 (a blend of 70 to 85 percent ethanol and 30 to 15 percent gasoline by volume), including the discounts on an energy-equivalent basis relative to motor gasoline that are required to meet the renewable fuels standard (RFS) legislated in Public Law 110-140, the Energy Independence and Security Act of 2007 (EISA2007),
decline to $2.39 per gallon in 2015, then rise gradually with the cost of building additional E85 infrastructure to expand its availability.

After declining at the end of 2008, natural gas prices stabilize through 2011, with Henry Hub spot prices just above $6.50 per million British thermal units (Btu). After 2011, Henry Hub spot prices (in 2007 dollars) begin to increase, reaching $9.25 per million Btu in 2030.

The price of natural gas is generally higher in the AEO2009 reference case than was projected in the AEO2008 reference case, as a result of higher exploration and development costs and a requirement for increased natural gas production (to meet increased consumption while imports are decreasing), particularly during the last 10 years of the projection. Total natural gas consumption is about 7 percent higher in 2030 as a result of a 40-percent increase in natural gas use for power generation, and net imports are 78 percent lower. The wellhead price of natural gas in 2030 is 23 percent higher in the AEO2009 reference case than in the AEO2008 reference case.

Coal prices are expected to moderate somewhat in the near term from their recent very high levels, but they remain well above the price projections of recent AEOs and rise toward the end of the projection as consumption grows. Average real minemouth coal prices (in 2007 dollars) in the AEO2009 reference case increase from $1.27 per million Btu ($25.82 per short ton) in 2007 to $1.47 per million Btu ($30.01 per short ton) in 2009, then level off and even decline somewhat, bottoming out at $1.39 per million Btu ($27.94 per short ton) in 2020. Much of the moderation in coal prices after 2009 is attributable to a shift from more expensive coal production from the Central
Appalachian supply region to regions with lower production costs, such as Northern Appalachia, the Eastern Interior, and Wyoming’s Powder River Basin. After 2020, coal prices rise to $1.45 per million Btu ($28.94 per short ton) in 2030.

The incorporation of tax credits for renewable systems and energy-efficient appliances in EIEA-2008, along with higher prices for natural gas and heating oil, contributes to a reduction in energy use in the AEO2009 reference case relative to the AEO2008 reference case (0.5 quadrillion Btu or 4 percent of delivered energy). Residential delivered energy consumption in the AEO2009 reference case grows from 11.4 quadrillion Btu in 2007 to 12.4 quadrillion Btu in 2030 (see Figure 2 on right).

Increased use of compact fluorescent lamps and the incorporation of efficiency standards for residential lighting from EISA2007 that promote the widespread use of light-emitting diode (LED) bulbs later in the projection significantly reduce electricity demand in the residential sector.

EIEA2008 removes the existing tax credit cap for the installation of solar photovoltaic systems, causing the installed stock of the systems to increase to 1.65 million (from fewer than 75,000 in a case without the tax credit) in 2016, the last year in which the credit is available.

Ground-source (geothermal) heat pumps also benefit from a large increase in the allowable credit in EIEA2008 (from $300 to $2,000 per unit), fostering nearly a threefold increase in the stock of very efficient heat pumps by 2016, relative to a case without the tax credit. Even though the tax credit spurs additional purchases of ground-source heat pumps, however, their market share remains low, reaching 1.0 percent of the single-family heating market by 2016.

Despite faster growth in commercial square footage, higher energy prices lead to slower growth in commercial energy consumption in the AEO2009 reference case relative to the AEO2008 reference case, along with increased adoption of energy conservation and efficiency measures. Delivered commercial energy consumption grows from 8.5 quadrillion Btu in 2007 to 10.6 quadrillion Btu in 2030, about 0.7 quadrillion Btu less than in the AEO2008 reference case.

Total U.S. consumption of liquid fuels, including both fossil liquids and biofuels, grows from 40.8 quadrillion Btu (20.6 million barrels per day) in 2007 to 41.6 quadrillion Btu (21.6 million barrels per day) in 2030 in the AEO2009 reference case (see Figure 3 on right). Excluding growth in biofuel consumption, consumption of petroleum-based liquids is essentially flat. The transportation sector dominates demand for liquid fuels, which grows from a 69-percent share of total consumption in 2007 to a 75-percent share in 2030.

Rapid growth in the consumption of renewable fuels results mainly from the implementation of the Federal RFS for transportation fuels and State renewable portfolio standard (RPS) programs for electricity generation. Given the anticipated level of technology improvement, the rate of investment, and the current schedule of mandates in the RFS, the requirement for cellulosic biofuels will be met at a level lower than the original EISA-2007 mandate through the implementation of waivers and adjustments. Growth in renewable electricity other than hydropower provides 33 percent of the growth in electricity demand between 2007 and 2030, and its share in meeting demand growth probably would be higher if existing production tax credits scheduled to expire in 2009 were extended, or if policies were implemented to limit GHG emissions.

Total primary energy consumption in the AEO2009 reference case grows by 11.2 percent, from 101.9 quadrillion Btu in 2007 to 113.3 quadrillion Btu in 2030 (4.7 quadrillion Btu less than in the AEO2008 reference case). Among the most important factors leading to lower total energy demand in the AEO2009 reference case are significantly higher energy prices and greater use of more efficient appliances and vehicles in response to the requirements of EISA2007 and EIEA2008.

In the AEO2009 reference case, natural gas consumption ranges between 22.5 and 23.4 trillion cubic feet through 2020 before increasing gradually to 24.4 trillion cubic feet in 2030—1.7 trillion cubic feet more than projected in the AEO2008 reference case. Despite higher natural gas prices, electric power sector consumption in 2030 is 2.0 trillion cubic feet higher in the AEO2009 reference case than in the AEO2008 reference case, in part because uncertainty about potential GHG regulations and their impact on coal use leads to an increase in natural gas use for electric power generation, offsetting lower consumption in the residential, commercial, and industrial sectors.

The energy intensity of the U.S. economy declines steadily as the result of higher energy prices and the adoption of policies that promote improved energy efficiency in the AEO2009 reference case.

The reference case reflects observed historical relationships between energy prices and energy conservation. To the extent that consumer preferences change, the improvement in energy intensity or energy consumption per capita could be greater or smaller.

Energy intensity, measured as primary energy use (in thousand Btu) per dollar of GDP (in 2000 dollars), declines by more than one-third from 2007 to 2030 in the AEO2009 reference case (see Figure 4 on right). Although energy use generally increases as the economy grows, higher energy prices, continuing improvement in energy efficiency, and a shift to less energy-intensive activities keep the rate of energy consumption growth lower than the rate of GDP growth.

Since 1992, the energy intensity of the U.S. economy has declined on average by 2.0 percent per year, in part because the share of industrial shipments accounted for by the energy-intensive industries has fallen from 24 percent in 1992 to 22 percent in 2007. In the AEO2009 reference case, the energy-intensive industries’ share of total industrial shipments continues to decline, to 18 percent in 2030.