2. Impacts of Modeled H.R. 6 EH Provisions

This analysis begins with a summary, followed by a discussion of each major provision. The impacts of provisions that affect oil and natural gas production are discussed first, followed by provisions that affect end-use markets.

The summary of impacts described in this chapter compare a modified AEO2005 reference case to a case that contains those H.R. 6 EH provisions modeled in NEMS. Although Senators Domenici and Bingaman requested a comparison to the reference case, world oil prices are now substantially higher than those shown in the reference case.⁵ The text box on page 12 gives a brief description of the effect of higher oil prices on the reference case projections for ethanol use.

Comparison of Selected Energy Performance Indicators

The H.R. 6 EH provisions analyzed in this report have a modest impact on energy production, imports, oil prices, overall energy consumption, and the overall economy. The most significant impact comes from opening the coastal plain of the Arctic National Wildlife Refuge (ANWR) to drilling.

The maximum annual difference from the reference case level of energy production is 2.2 quadrillion British thermal units (Btu) in 2025 or 2.7 percent (Table 1). Until oil production from ANWR begins in 2015, the difference in total energy production between the H.R. 6 EH case and the reference case is less than 0.1 percent.

Starting in 2016, increased oil production from ANWR and other fields in Alaska accounts for most of the increase in energy production in the H.R. 6 EH case. Alaska oil production is 940,000 barrels per day (154 percent) higher in the H.R. 6 EH case than the reference case in 2025. Smaller increases are also seen in the production of natural gas (because of royalty relief) and ethanol (because of a renewable fuel standard).

Energy imports in the H.R. 6 EH case are less than in the reference case, primarily because of lower oil imports. Net petroleum imports in the H.R. 6 EH case are 1.0 million barrels per day less than in the reference case in 2025, with more than 90 percent of the difference coming from reduced imports of crude oil. Opening ANWR reduces import dependence by 4 percentage points, from 68 percent of petroleum product supplied in 2025 to 64 percent.

The difference in total energy consumption between the reference and H.R. 6 EH cases is less than 0.1 percent in all years. Residential and commercial initiatives in H.R. 6 EH reduce consumption by a small amount, while industrial production increases by a small amount, as drilling and production increase in Alaska.

The most significant impact on energy prices caused by H.R. 6 EH is the reduction in world oil prices from the opening of ANWR. In 2025, world oil prices are expected to be 57 cents per barrel (1.9 percent) less than in the reference case in constant 2003 dollars.

Macroeconomic activity is not significantly affected by the modeled provision of H.R. 6 EH . Gross domestic product increases starting with the opening of ANWR in 2015 and is $14 billion (less than 0.1 percent) higher than the reference case in constant 2000 dollars in 2025.

Oil and Natural Gas Supply Provisions

Royalty Relief

Sections 2005 and 2016 of H.R. 6 EH are intended to promote oil and natural gas development from resources in Federal waters and lands by providing royalty relief. In both these provisions, the Secretary of the Interior may place limitations on the suspension of royalty relief granted based on market prices, but the specifics are not provided.

Section 2005 provides royalty relief for oil and natural gas production in water depths greater than 400 meters in the Gulf of Mexico from any oil or gas lease sale occurring within 5 years after enactment. The minimum volume of production with suspended royalty payments is:

• 5,000,000 barrels of oil equivalent (BOE) for each lease in water depths of 400 to 800 meters
• 9,000,000 BOE for each lease in water depths of 800 to 1,600 meters
• 12,000,000 BOE for each lease in water depths of 1,600 to 2,000 meters
• 16,000,000 BOE for each lease in water depths greater than 2,000 meters.

Section 2016 provides royalty relief for natural gas produced from onshore deep wells drilled after enactment. The maximum suspension volume is 50 billion cubic feet per lease. The definition of “deep well” is not specified in the provision.

To analyze these royalty relief provisions, the following assumptions were used:

• The water depth categories in Section 2005 were adjusted to be consistent with the depth categories in the Offshore Oil and Gas Supply Submodule of NEMS. The suspension volumes are 5,000,000 BOE for leases in water depths 200 to 800 meters; 9,000,000 BOE for leases in water depths of 800 to 1,600 meters; 12,000,000 BOE for leases in water depth of 1,600 to 2,400 meters; and 16,000,000 for leases in water depths greater than 2,400 meters. Examination of the resources available at 200 to 400 and 2,000 to 2,400 meters showed that the differences between the depths used in NEMS and those specified in the bill would not materially affect the results.
• Onshore wells drilled to depths greater than 10,000 feet were considered deep. Wells drilled after 2005 received a suspension of royalties on 50 billion cubic feet per lease.
• Royalty relief was applied if the regional wellhead price was less than $32 (in 2002 dollars) for oil and $4 (in 2002 dollars) for natural gas.

Royalty relief as specified for Sections 2005 and 2016 of H.R. 6 EH is projected to increase cumulative lower-48 offshore oil production between 2006 and 2025 by 0.5 percent. Cumulative lower-48 natural gas production is projected to be the same in the H.R. 6 EH case as in the reference case.

Arctic National Wildlife Refuge

Sections 2201 through 2212 of H.R. 6 EH allow the opening of the coastal plain (Section 1002 Area) of ANWR to oil and natural gas exploration and development. This analysis includes production from Federal lands, native lands, and State offshore areas of the coastal plain. The U.S. Geological Survey (USGS) estimates that 74 percent of the oil resources in ANWR’s coastal plain are on Federal lands, with the remaining 26 percent on State and tribal lands. The link between development on Federal and tribal lands is legally driven—under terms of the Alaska National Interest Lands Conservation Act of 1980, development on native lands can only proceed after a Congressional decision to open the coastal plains of ANWR. The link between development in Federal lands and State areas is economic—without ANWR development the necessary infrastructure for offshore development would likely not be available. Since both the State and native corporations have expressed a strong interest in developing their respective oil resources, an approach that reflects the legal and economic linkages operating on the North Slope is appropriate in evaluating the potential production impact of a Congressional decision to allow development in ANWR.

The key assumptions used to project crude oil production from the coastal plain of ANWR are as follows:

• First production from ANWR occurs 10 years after the passage of the legislation (i.e. 2015), assuming that the first lease sale occurs 22 months after enactment.
• New fields in the coastal plain of ANWR are sequentially developed every 2 years after a prior field begins production.
• The total volume of technically recoverable crude oil resources is assumed to be 10.4 billion barrels (USGS mean estimate).⁶ The largest field is 1.37 billion barrels of oil and is brought into production first. Subsequent fields that are developed through 2025 are smaller—two fields with 700 million barrels of oil and three fields with 360 million barrels of oil.
• Fields are assumed to take 3 to 4 years to reach peak production, maintain peak production for 3 to 4 years, and then decline until they are no longer profitable and are closed.

The opening of the coastal plain of Alaska to development is projected to increase domestic oil production starting in 2015. Between 2015 and 2025, cumulative oil production from Alaska is projected to be 2.4 billion barrels (40.1 percent) higher than in the reference case.

Summary of Crude Oil and Natural Gas Market Impacts from H.R. 6 EH Provisions

The H.R. 6 EH provisions for crude oil and natural gas supply are expected to increase domestic production over the projection period (Table 2). Cumulative oil production between 2006 and 2025 is projected to be 2.46 billion barrels (5.6 percent) higher in the H.R. 6 EH case than in the reference case. The majority (97 percent) of the increase in domestic crude oil supply comes from ANWR. The increase in domestic supply reduces oil import dependency in 2025 from 68 percent in the reference case to 64 percent in the H.R. 6 EH case and is projected to reduce the world oil price by 57 cents per barrel (1.9 percent) relative to the reference case in 2025.

The net impact of the H.R. 6 EH oil and natural gas provisions on domestic natural gas production is small. Between 2006 and 2025, cumulative dry natural gas production is projected to be 0.61 trillion cubic feet (0.1 percent) higher in the H.R. 6 EH case than in the reference case. However, not all of this increase is marketed production. The opening of the coastal plain of ANWR to oil and natural gas development is expected to increase natural gas production for lease and plant fuel use, not for marketing to the lower-48 States. Cumulative lower-48 natural gas production is about the same between the two cases, and average wellhead prices are only slightly lower in the H.R. 6 EH case.

Downstream Fuel Provisions

Section 1501 of H.R. 6 EH establishes a renewable fuels program (RFP) that requires 3.1 billion gallons of renewable fuels to be blended into transportation sector in 2005, increasing to 5 billion gallons by 2012. For 2013 and each year thereafter, the renewable fuels required would be proportional to the total gasoline sold nationally.⁷ Both ethanol and biodiesel are considered as renewable fuels, with a 1.5-gallon credit toward the RFP for every gallon of biomass ethanol produced. Cellulose ethanol produced from agricultural or wood residue is given a 2.5-gallon credit; however because NEMS generates only one biomass price, in this study all cellulose ethanol was assumed to get only 1.5-gallon credits.

Section 1504 of H.R. 6 EH prohibits the use of MTBE nationwide starting in 2015⁸ yet allows States to seek a waiver from the U.S. Environmental Protection Agency to allow the continued use of MTBE. The H.R. 6 EH case assumes no States request or obtain such waivers. Section 1503 provides merchant MTBE producers with grant assistance of up to $250 million per year between 2005 and 2012 to convert to iso-octane production. If economical, merchant MTBE producers are assumed to convert their units to iso-octane. Grants to convert merchant MTBE plants accelerate conversion of the plants to other uses but do not significantly affect petroleum supply. Section 1506 of H.R. 6 EH also eliminates the oxygen content requirement for reformulated gasoline starting in 2006.⁹ This provision was incorporated into the H.R. 6 EH case.

The American Jobs Creation Act of 2004 extended the Federal tax credit of $0.51 per gallon on ethanol blended into gasoline through 2010. Since the Federal tax credit for ethanol has been extended several times in the past, both the H.R. 6 EH and reference cases assume the tax credit will be extended indefinitely. The Jobs Creation Act also provides a tax credit of $0.50 per gallon of biodiesel produced from recycled oil or $1.00 per gallon of biodiesel produced from virgin oil or virgin animal fat and applies to biodiesel blended with petroleum diesel. This credit is effective from December 31, 2003, through December 31, 2006.

Section 1512 of H.R. 6 EH authorizes the Secretary of Energy to approve grants to potential producers of cellulose ethanol: $100 million to be made available in fiscal year 2005, $250 million in fiscal year 2006, and $400 million in fiscal year 2007. A cellulose ethanol plant with capacity of 52 million gallons per year is estimated to cost $250 million (2004 dollars) to construct. The H.R. 6 EH case assumes that cellulose ethanol will develop first on the West Coast, since there is an ample supply of biomass, substantial demand for ethanol, and very little conventional ethanol production. It is assumed that the grants will completely fund the construction of the first two plants, which will begin operation in 2008. The third plant will be constructed with the remainder of the grant money plus $32 million (2004 dollars) of investor capital and will begin operation in 2009.

Table 3 summarizes the major impacts of the H.R. 6 EH on the downstream petroleum market.¹⁰ The RFP requirements would increase the ethanol consumption by 0.39 billion gallons in 2010, 1.7 billion gallons in 2015, and 1.8 billion gallons in 2025. Relative to the ethanol consumption of 2.8 billion gallons in 2003, this represents an increase in ethanol consumption of 59 percent by 2010, 103 percent by 2015, and 126 percent by 2025. Ethanol accounts for essentially all of the additional renewable transportation fuels consumption compared to the reference case. Neither the RFP nor the short-term tax incentives are expected to affect the biodiesel supply significantly.

The H.R. 6 EH case projects impacts of less than 1 cent per gallon on average gasoline prices throughout most of the forecast horizon, because other provisions of the bill increase the costs of using a more expensive blending component (ethanol). For example, the increases in domestic oil production are anticipated to reduce crude oil prices by 57 cents a barrel by 2025. Additionally the MTBE plant conversation assistance provides additional octane-boosting blending components that are less expensive than many petroleum-based alternatives.

Summary of Impacts on Transportation Fuels from H.R. 6 EH Provisions

The H.R. 6 EH provisions for transportation fuels include the implementation of an RFP that seeks to increase the quantity of renewable fuel (primarily ethanol) blended, from about 2.8 billion gallons in 2003 to 5 billion gallons by 2012. In 2013 and beyond, the share of renewable fuel is to remain proportional to the 2012 share of gasoline sold in the Nation thereafter. This increase is projected to cost no more than 1 cent per gallon of blended gasoline. The use of the oxygenate MTBE would be prohibited by H.R. 6 EH nationwide starting in 2015, and the oxygen content requirement for RFG would be eliminated starting in 2006.

Residential and Commercial Provisions

Residential Sector

Appliance standards, tax credits, and subsidies are included in the suite of provisions aimed at reducing residential energy use. Section 133 of H.R. 6 EH includes a standard that limits the output of torchiere lights to 190 watts per bulb, effective January 1, 2006. Today, torchiere bulbs in the 250-watt range are common in the marketplace, allowing room for future energy savings. In 2015, the torchiere standard is projected to save 8 billion kilowatthours (3 percent of residential lighting demand and 0.5 percent of overall residential electricity use), increasing to 9 billion kilowatthours by 2025 (3 percent of lighting demand and 0.5 percent of overall residential electricity use).

Increases in funding for weatherization programs in Section 122 of H.R. 6 EH and tax credits for existing homes in Section 1317 of H.R. 6 EH are projected to reduce heating and cooling requirements by about 30 percent in the homes that are affected by either the subsidy or the tax credit. These measures are projected to save 34 trillion Btu of delivered energy in 2015 (0.3 percent) and 28 trillion Btu in 2025 (0.2 percent). For the increase in weatherization funding in Section 122, an additional 360,000 homes (0.3 percent of the 2004 stock) would be upgraded in 2006 through 2008. Some 1.1 million households could claim the existing home tax credit in 2006 and 2007, which represents less than 1 percent of the housing stock in 2004. The tax credits for purchases of renewable technologies included in Section 207 of H.R. 6 EH have a measurable impact on the purchase of ground-source heat pumps, nearly doubling the stock of this little-used technology by 2025. Even still, ground-source heat pumps only account for 0.7 percent of the heating equipment stock in 2025 in the H.R. 6 EH case. Table 4 summarizes projected reductions in energy consumption and expenditures in the H.R. 6 EH case, relative to the reference case.

Commercial Sector

Section 133 of H.R. 6 EH provides specific conservation standards for illuminated exit signs, traffic signals, and low voltage dry-type transformers manufactured on or after January 1, 2006. The provision requires exit signs to meet Version 2.0 Energy Star performance requirements.¹¹ Power usage of 5 watts or less with size and luminance levels also specified. Low voltage dry-type transformers must meet the Class I Efficiency Levels specified by the National Electrical Manufacturers Association.¹² The provision also requires traffic signal modules to meet Energy Star performance requirements. To estimate the impacts of these standards, electricity use reductions relative to reference case assumptions were estimated and included in the H.R. 6 EH case. The standards are projected to reduce commercial delivered electricity demand in the “Other Uses” category by about 6 trillion Btu (2 billion kilowatthours or 0.1 percent) in 2010 and about 12 trillion Btu (4 billion kilowatthours or 0.2 percent) annually in 2015 through 2025 as the existing equipment stock is replaced and the effects of the standards are realized.

Section 205 of H.R. 6 EH establishes a photovoltaic energy commercialization program, including the installation of at least 150 megawatts of capacity in public buildings cumulatively from 2006 through 2010. The provision authorizes $50 million per year for the 5-year program, about one- third of the funds needed to install the full 150 megawatts specified in the bill. To estimate the impact of the provision, extra “program-driven” commercial photovoltaic capacity was added over the 5-year program equal to about 48 megawatts, the capacity consistent with the authorized funding. The additional photovoltaic capacity installed for this provision is projected to generate about 101 million kilowatthours of electricity annually post-2009, about 4.8 percent of total commercial sector electricity use in 2025.

Section 1312 provides a 15-percent business investment tax credit for fuel cell systems up to a maximum of $500 per 0.5 kilowatt of capacity. Qualifying equipment must have electrical capacity of at least 0.5 kilowatts and be placed in service from April 2005 through 2007. Fuel cell adoption is limited because current system costs are more than $5,000 per kilowatt and the timeframe of the credit is short. Very few additional sales of fuel cells would be purchased as a result of the tax credit.

Supply-driven energy price effects for commercial consumers as a result of other provisions in H.R. 6 EH are minimal, allowing commercial projected energy savings to persist throughout the forecast. Composite energy prices are projected to be 0.1 percent lower and energy expenditures 0.2 percent lower in 2025 (Table 5).

2. Impacts of Modeled H.R. 6 EH Provisions Tables

Notes