TAX EXPENDITURES FOR ENERGY PRODUCTION 

AND CONSERVATION 

Scheduled for a Public Hearing 

Before the 

SENATE COMMITTEE ON FINANCE 

on April 23, 2009 

Prepared by the Staff 

of the 

JOINT COMMITTEE ON TAXATION 

April 21, 2009 

JCX-25-09
i 

CONTENTS 

Page

I. INTRODUCTION AND SUMMARY TABLES .................................................................. 1

A. Summary of Credit for Electricity Produced from Certain Renewable Resources ......... 2

B. Summary of Certain Renewable and Alternative Fuel Incentives ................................... 3

C. Summary of Investment Tax Credit Energy Production Incentives ................................ 4

D. Summary of Energy Conservation Credits ...................................................................... 5

E. Summary of Alternative Fuel Vehicle Credits ................................................................. 6

F. Summary of Certain Non-Fossil Fuel Capital Cost Recovery Provisions ..................... 10

G. Summary of Fossil Fuel Capital Cost Recovery Provisions .......................................... 11

H. Summary of Energy Credits Related to Fossil Fuels ..................................................... 13

I. Summary of Other Energy Provisions ........................................................................... 16

J. Summary of Energy-Related Bond Provisions .............................................................. 19

II. DESCRIPTION OF PRESENT LAW ................................................................................. 21

A. Tax Provisions Relating to Renewable Energy ............................................................. 21

1. Credit for alternative fuel vehicle refueling property (sec. 30C) ............................. 21

2. Incentives for alcohol, cellulosic biofuel, biodiesel, renewable diesel, and 

certain alternative fuels (secs. 40, 40A, 6426, and 6427(e)) .................................... 22

3. Renewable electricity production credit (sec. 45) .................................................... 30

4. Energy credit (sec. 48) ............................................................................................. 35

5. Clean renewable energy bonds and new clean renewable energy bonds 

(secs. 54 and 54C) .................................................................................................... 38

6. Five-year cost recovery of certain energy property (sec. 168) ................................ 44

7. Special allowance for cellulosic biofuel plant property (sec. 168(l)) ...................... 46

B. Provisions Relating to Energy Conservation ................................................................. 48

1. Credit for nonbusiness energy property (sec. 25C) ................................................. 48

2. Credit for residential energy efficient property (sec. 25D) ...................................... 50

3. Alternative and plug-in electric-drive motor vehicle credits (secs. 30, 30B, 

and 30D)................................................................................................................... 51

4. New energy efficient home credit (sec 45L of the Code) ........................................ 59

5. Energy efficient appliance credit (sec. 45M of the Code) ....................................... 60

6. Qualified energy conservation bonds (sec. 54D) ..................................................... 61

7. Energy efficient commercial buildings deduction (sec. 179D ) .............................. 68

8. Energy Conservation Subsidies Provided by Public Utilities (sec. 136) ................. 70

C. Provisions Relating to Fossil Fuel Extraction ................................................................ 71

1. Credit for enhanced oil recovery costs (sec. 43) ...................................................... 71

2. Credit for the production of Indian coal (sec. 45) .................................................... 71

3. Marginal wells credit (sec. 45I) ............................................................................... 72

4. Recovery of intangible drilling and development costs (secs. 59, 263, and 291).... 72

5. Deduction for qualified tertiary injectants (sec. 193) .............................................. 74

6. Arbitrage exception for prepayments of natural gas (sec. 148) ............................... 74

7. Amortization of geological and geophysical expenditures (sec. 167(h)) ................ 77

8. Passive loss rules for working interests in oil and gas property (sec. 469) ............. 78

9. Depletion (secs. 611-613A) ..................................................................................... 79
ii 

D. Provisions Relating to Refining ..................................................................................... 84

1. Tax incentives for refining (secs. 45H, 168, 179B, and 179C) ............................... 84

2. Credit for producing coke or coke gas (sec. 45K) ................................................... 85

E. Provisions Relating to Energy Transportation or Transmission .................................... 86

1. Cost recovery of certain energy transportation and transmission property 

(sec. 168(e)(3)) ......................................................................................................... 86

2. Five-Year carryback of net operating losses for certain electric utility 

companies (sec. 172(b)(1)(I)) .................................................................................. 88

3. Deferral of gains from the sale of electric transmission property (sec. 451(i)) ....... 89

F. Provisions Relating to Coal and Nuclear Energy .......................................................... 91

1. Credit for the production of refined coal (sec. 45) ................................................... 91

2. Advanced nuclear power production credit (sec. 45J) ............................................. 92

3. Credit for carbon dioxide sequestration (sec. 45Q) ................................................. 93

4. Advanced coal project credit (sec. 48A) .................................................................. 94

5. Gasification investment credit (sec. 48B) ................................................................ 96

6. Pollution Control Facilities (sec. 169) ..................................................................... 97

7. Special rules for nuclear decommissioning costs (sec. 468A) ................................. 98

G. Provisions Relating to General Energy-Related Projects and Research ...................... 100

1. Energy research credit (sec. 41) ............................................................................. 100

2. Credit for investment in advanced energy property (sec. 48C) ............................. 101

H. Miscellaneous Energy Provisions ................................................................................ 103

1. Tax-exempt bonds for power facilities (secs. 103, 141, and 142) ......................... 103

2. Reduced rate of tax for diesel-water fuel emulsion (secs. 4081(a)(2)(D), 

4081(c), and 6427(m)) ........................................................................................... 107

3. Exceptions for publicly traded partnerships treated as corporations 

(secs. 7704 and 851) .............................................................................................. 107

III. DATA AND ANALYSIS .................................................................................................. 109
1

I. INTRODUCTION AND SUMMARY TABLES 

The Senate Committee on Finance has scheduled a public hearing on April 23, 2009, 

titled “Technology Neutrality in Energy Tax: Issues and Options.” Since 2004, the Congress 

has been very active in promulgating legislation related to energy production (including oil and 

gas and renewables) and conservation. Part II of this document,1 prepared by the staff of the 

Joint Committee on Taxation, provides a description of present law tax expenditures for energy 

production and conservation. These tax provisions vary widely, and are summarized in the 

tables that follow. In addition to the energy specific tax expenditures, energy sector producers 

and manufacturers may also benefit from other general tax expenditures, such as the section 199 

deduction for income attributable to domestic production activities, additional first year 

depreciation (“bonus depreciation”), the lower rates of tax on the first $10 million of corporate 

taxable income, and, in general, the deferral of tax on active business income derived by foreign 

subsidiaries. 

The various tax benefits create incentives that have the potential to affect economic 

decisions and allocate economic resources from other uses to the tax-favored uses. Such tax 

preferences may produce an allocation of resources that is more efficient for society at large if 

they are properly designed to overcome negative effects (such as atmospheric pollution, for 

example) that would otherwise result from a purely market based outcome without any 

government intervention. The extensive variety of tax expenditures for energy production and 

conservation have been criticized for lacking well defined objectives, and for lacking 

coordination among provisions having similar objectives. Some argue that the simultaneous 

existence of tax preferences for the fossil fuel industry and for renewable energy production 

represents an incoherent government policy. Others have noted that the incentives for renewable 

energy and conservation are not themselves designed in a coordinated way to produce the most 

efficient or equitable subsidies for renewable energy and conservation. 

Part III of this document provides the staff of the Joint Committee on Taxation’s most 

recent estimates of tax expenditures in the energy sector, a brief discussion of the economic 

rationale for certain government intervention in energy markets through the tax code, and issues 

related to the proper design of such tax preferences. 

 1

 This document may be cited as follows: Joint Committee on Taxation, Tax Expenditures for 

Energy Production and Conservation (JCX-25-09) April 21, 2009. This document can also be found on 

our website at www.jct.gov. 
2

A. Summary of Credit for Electricity Produced from 

Certain Renewable Resources 

Eligible electricity 

production activity (sec. 45) 

Credit amount for 

20083

 (cents per 

kilowatt-hour) 

Credit period for 

facilities placed 

in service on or 

before August 8, 

2005 (years from 

placed-in-service 

date) 

Credit period for 

facilities placed in 

service after 

August 8, 2005 

(years from 

placed-in-service 

date) 

Wind 2.1 10 10 

Closed-loop biomass 2.1 101 10 

Open-loop biomass 

 (including agricultural 

 livestock waste nutrient 

 facilities) 

1.0 52 10 

Geothermal 2.1 5 10 

Solar (pre-2006 facilities only) 2.1 5 10 

Small irrigation power 1.0 5 10 

Municipal solid waste 

 (including landfill gas 

 facilities and trash 

 combustion facilities) 

1.0 5 10 

Qualified hydropower 1.0 N/A 10 

Marine and hydrokinetic 1.0 N/A 10 

1

 In the case of certain co-firing closed-loop facilities, the credit period begins no earlier than October 22, 

2004. 

2

 For certain facilities placed in service before October 22, 2004, the five-year credit period commences 

on January 1, 2005. 

3

 Inflation adjusted amounts for 2009 are not yet available. 
3

B. Summary of Certain Renewable and Alternative Fuel Incentives 

Fuel Type Per Gallon Incentive Amount Incentive Expires 

Agri-biodiesel and biodiesel $1.00 per gallon, plus 

$0.10 per gallon for small 

 agri-biodiesel producers 

 December 31, 2009 

Renewable diesel $1.00 per gallon December 31, 2009 

Alcohol fuel (not ethanol and other 

than from natural gas or coal) $0.60 per gallon December 31, 2010 

Ethanol fuel $0.45 per gallon, plus 

$0.10 per gallon for small 

 producers 

December 31, 2010 

Cellulosic biofuel $1.01 per gallon (for alcohol, 

$1.01 per gallon less the amount of 

the alcohol fuel mixture credit and 

small ethanol producer’s credit in 

effect at the time of production) 

December 31, 2012 

Alternative fuel: 

 liquefied petroleum gas 

 P Series Fuels 

 compressed or liquefied natural 

gas 

 liquefied hydrogen 

 any liquid fuel derived from coal 

through the Fischer-Tropsch 

process 

 compressed or liquified gas 

derived from biomass 

 liquid fuel derived from biomass 

$0.50 per gallon December 31, 2009 

(September 30, 2014, in the 

case of liquefied hydrogen) 
4

C. Summary of Investment Tax Credit Energy Production Incentives 

Credit 

rate 

Maximum 

credit Expiration 

Energy credit 

(sec. 48)

Equipment to produce a 

geothermal deposit 10% none None 

Equipment to use ground or 

ground water for heating or 

cooling 

10% none December 31, 2016 

Microturbine property (< 2 

Mw electrical generation 

power plants of >26% 

efficiency) 

10% $200 per Kw 

of capacity December 31, 2016 

Combined heat and power 

property (simultaneous 

production of 

electrical/mechanical power 

and useful heat > 60% 

efficiency) 

10% none December 31, 2016 

Solar electric or solar hot 

water property 

30% (10% 

after 

December 

31, 2016) 

none None 

Fuel cell property (generates 

electricity through 

electrochemical process) 

30% 

$1,500 for 

each 1⁄2 Kw 

of capacity 

December 31, 2016 

Small (<100 Kw capacity) 

wind electrical generation 

property 

30% none December 31, 2016 
5

D. Summary of Energy Conservation Credits 

Credit 

rate or 

amount

Maximum 

credit Expiration 

Personal credits:

Nonbusiness energy 

property credits (sec. 25C)

Insulation to international energy 

conservation code standard 30 % $1,500 December 31, 2010 

Energy efficient Windows, doors, 

skylights,roofs 30 % 

$1,500 December 31, 2010 

Advanced main air circulating fans 

30 % 

$1,500 December 31, 2010 

Qualified natural gas, propane, or oil 

furnace or hot water boilers 30 % 

$1,500 December 31, 2010 

Electric heat pump water heaters or 

natural gas, propane, or oil water heaters 

30 % $1,500 December 31, 2010 

Central air conditioners 30 % $1,500 December 31, 2010 

Biomass fuel property (wood stoves) 30 % $1,500 

Residential energy efficient 

property credits (sec. 25D)

Residential solar water heating or solar 

electric property 

30 % none December 31, 2016 

Residential small wind property 30 % none December 31, 2016 

Residential geothermal heat pump 

property 

30 % none December 31, 2016 

Residential fuel cell property 30 % $500 per half 

kilowatt of 

capacity 

December 31, 2016 

Business Credits:

Manufacturer credit for 

new energy efficient home 

(sec. 45L)

Homes 30% more efficient than standard $1,000 

per home 

none December 31, 2009

Homes 50% more efficient than standard $2,000 

per home 

none December 31, 2009

Manufacturer credit for 

energy efficient appliances 

(sec. 45M)

Dishwashers $45 (1) December 31, 2009 

Dishwashers (higher efficiency standard) $75 (1) December 31, 2010 

Clothes washers $125 (1) December 31, 2009 

Clothes washers (higher efficiency 

standard) 

$150 (1) December 31, 2010 

Clothes washers (highest efficiency 

standard) 

$250 none December 31, 2010 

Refrigerators $75 (1) December 31, 2009 

Refrigerators (higher efficiency standard) $100 (1) December 31, 2010 

Refrigerators (highest efficiency 

standard) 

$200 none December 31, 2010 

1 A given manufacturer may not claim credits in excess of an aggregate of $75 million for taxable years beginning 

after December 31, 2007, with respect to all credits excepting the $200 credit for refrigerators and the $250 credit 

for clothes washers. 
6 

E. Summary of Alternative Fuel Vehicle Credits 

Type of Property Description of Qualifying 

Property Credit Amount and Explanation Expiration 

Fuel cell vehicles 

(sec. 30B) 

Vehicles propelled by 

chemically combining 

oxygen with hydrogen and 

creating electricity 

 Base credit of $8,000 (reduced to 

$4,000 after 2009) for vehicles 

weighing 8,500 pounds or less 

 Heavier vehicles can get up to a 

$40,000 credit, depending on 

weight 

 An additional $1,000 to $4,000 

credit is available to cars and light 

trucks to the extent fuel economy 

exceeds 2002 base fuel economy

12/31/2014 

Hybrid vehicles 

(sec. 30B) 

Vehicles powered by 

internal combustion 

engine and a rechargeable 

energy storage system 

(e.g. batteries) 

 Base credit of $400 to $2,400 for 

cars and light trucks (weighing 

8,500 pounds or less) depending on 

amount by which fuel economy 

exceeds 2002 base fuel economy 

 Additional conservation credit for 

cars and light trucks of between 

$250 and $1,000 depending on 

estimated lifetime fuel savings 

relative to a comparable 2002 

model year vehicle powered solely 

by a gasoline or diesel engine 

 For heavy hybrid vehicles, the 

credit varies between 20 and 40 

percent of the incremental cost 

depending on the amount by which 

the fuel economy of the vehicle 

exceeds that of a comparable 

vehicle. The maximum credit is 

$7,500 for vehicles weighing 

14,000 pounds of less; $15,000 for 

vehicles weighing more than 

14,000 pounds but less than 26,000 

pounds; $30,000 for vehicles 

weighing more than 26,000 

pounds. 

 12/31/2009 for 

cars and light 

trucks weighing 

8,500 pounds or 

less 

 12/31/2010 for 

heavier vehicles 

 60,000 vehicle 

per manufacturer 

limitation 

applies to cars 

and light trucks 
7 

Summary of Alternative Fuel Vehicle Credits (cont’d)

Type of Property Description of Qualifying 

Property Credit Amount and Explanation Expiration 

Lean burn 

vehicles 

(sec. 30B) 

 Cars and light trucks 

with internal 

combustion engines 

designed to use more 

air than necessary for 

complete combustion 

that incorporate direct 

injection and achieve 

at least 125 percent of 

the 2002 model year 

city fuel economy 

 Commonly referred to 

as clean diesel cars 

and trucks

Credit calculation is the same as for 

hybrid passenger vehicles and light 

trucks. 

 12/31/2010 

 60,000 vehicle 

per manufacturer 

limitation 

Alternative fuel 

vehicles 

(sec. 30B) 

 Vehicles that run 

solely on compressed 

natural gas, liquefied 

natural gas, liquefied 

petroleum gas, 

hydrogen, or any 

liquid fuel that is at 

least 85 percent 

methanol 

 Vehicles that run on a 

fuel mixture 75 

percent of which is 

one of the fuels listed 

above.

 Credit is 50 percent of the 

incremental cost of such vehicle 

above a comparable vehicle, plus 

an additional 30 percent if the 

vehicle meets certain emissions 

standards 

 Depending on vehicle weight, the 

maximum allowable credit varies 

between $5,000 (for vehicles 

weighing 8,500 pounds or less) to 

$40,000 (for vehicles weighing 

over 26,000 pounds) 

 Mixed-fuel vehicles using 90 

percent alternative fuel get 90 

percent of the credit; those using 

75 percent alternative fuel get 70 

percent of the credit

12/31/2010 
8 

Summary of Alternative Fuel Vehicle Credits (cont’d)

Type of Property Description of Qualifying 

Property Credit Amount and Explanation Expiration 

Plug-in electricdrive motor 

vehicles (2009) 

(sec. 30D) 

A four-wheeled vehicle 

propelled by a battery with 

at least 4 kilowatt-hours of 

electricity that can be 

charged from an external 

source 

 Base credit of $2,500 plus $417 for 

each kilowatt-hour of additional 

battery capacity in excess of 4 

kilowatt-hours. 

 Depending on vehicle weight, the 

maximum allowable credit varies 

between $7,500 (for vehicles 

weighing 10,000 pounds or less) to 

$15,000 (for vehicles weighing 

over 26,000 pounds)

 250,000 vehicle 

overall cap 

 Modified as 

described below 

after 2009 

Plug-in electricdrive motor 

vehicles (after 

2009) (sec. 30D) 

As described above, but 

excludes low speed 

vehicles and vehicles 

weighing 14,000 or more 

Credit is as described above except 

that the maximum credit is $7,500 

regardless of vehicle weight. 

200,000 vehicle per 

manufacturer 

limitation 

Electric-drive lowspeed, motorcycle, 

and three-wheeled 

vehicles 

(sec. 30) 

 Vehicles otherwise 

qualifying as plug-in 

electric-drive vehicles 

but for the fact that 

they have limited 

speed or less than four 

wheels 

 Two- and threewheeled vehicles must 

have a battery capacity 

of at least 2.5 kilowatthours

Credit is 10 percent of cost, up to 

$2,500. 

12/31/2011 

Converted plug-in 

electric-drive 

vehicles 

(sec. 30B) 

Used vehicles that have 

been converted into a 

plug-in electric drive 

motor vehicle 

Credit is 10 percent of conversion 

cost up to $4,000. 

12/31/2011 
9 

Summary of Alternative Fuel Vehicle Credits (cont’d)

Type of Property Description of Qualifying 

Property Credit Amount and Explanation Expiration 

Alternative fuel 

refueling property 

(sec. 30C) 

Property that dispenses 

alternative fuels, including 

ethanol, biodiesel, natural 

gas, hydrogen, and 

electricity 

 For 2009 and 2010, credit is 50 

percent of cost of qualified 

refueling property (other than 

hydrogen property) installed at a 

business or principal residence; 

hydrogen property gets a 30 

percent credit 

 For 2009 and 2010, credit may not 

exceed $200,000 for hydrogen 

refueling property used in a 

business, $50,000 for other 

business refueling property, and 

$2,000 for non-hydrogen refueling 

property installed at a principal 

residence 

 For years other than 2009 and 

2010, the credit rate is 30 percent, 

and the maximum allowable credit 

is $50,000 for business refueling 

property and $1,000 for property 

installed at a principal residence. 

 12/31/2010 for 

non-hydrogen 

refueling 

property 

 12/31/2014 for 

hydrogen 

refueling 

property 
10 

F. Summary of Certain Non-Fossil Fuel Capital Cost 

Recovery Provisions 

 Description of Provision Expiration 

Five-year cost 

recovery for certain 

energy property 

(sec. 168(e)(3)(B)(vi)) 

 A five-year MACRS recovery period is 

generally provided for equipment using solar 

and wind energy to generate electricity, to heat 

or cool (or provide hot water for use in) a 

structure, or to provide solar process heat; 

equipment using solar energy to illuminate the 

inside of a structure using fiber-optic distributed 

sunlight; equipment used to produce, distribute, 

or use energy derived from a geothermal 

deposit; and qualified fuel cell property. 

 A five-year MACRS recovery period is 

provided for certain biomass property, including 

(i) a boiler, the primary fuel for which will be an 

alternate substance; (ii) a burner (including 

necessary on-site equipment to bring the 

alternate substance to the burner) for a 

combustor other than a boiler if the primary fuel 

for such burner will be an alternate substance; 

(iii) equipment for converting an alternate 

substance into a qualified fuel; and (iv) certain 

pollution control equipment.

For five-year recovery 

period for certain solar 

equipment - December 

31, 2016 

Special allowance for 

cellulosic biofuel 

plant property 

(sec. 168(l)) 

An additional first-year depreciation deduction 

equal to 50 percent of the adjusted basis of 

qualified cellulosic biofuel plant property. 

December 31, 2012 

Pollution control 

facilities 

(secs. 169, 291) 

A taxpayer may elect to recover the cost of any 

certified pollution control facility over a period of 

60 months. A corporation taxpayer must reduce the 

amount of basis otherwise eligible for the 60-

month recovery by 20 percent. 

None 

Energy efficient 

commercial buildings 

deduction (sec. 179D) 

A taxpayer may take an additional deduction of 

$1.80 per square foot of commercial property that 

exceeds certain energy efficiency standards 

December 31, 2013 
11 

G. Summary of Fossil Fuel Capital Cost Recovery Provisions 

Description of Provision Expiration 

Geological & 

geophysical 

expenditures 

(sec. 167(h)) 

 Geological and geophysical (G&G) expenditures 

incurred by independent producers and smaller 

integrated oil companies in connection with domestic 

oil and gas exploration may be amortized over 24 

months. 

 G&G expenditures incurred by major integrated oil 

companies are amortized over seven years. 

None 

Alaska natural gas 

pipeline (sec. 

168(e)(3)(C)(iii)) 

Seven-year MACRS recovery period and a class life of 22 

years is provided for any natural gas pipeline system 

located in the State of Alaska that has a capacity of more 

than 500 billion Btu of natural gas per day and is placed in 

service after December 31, 2013. 

None 

Natural gas 

distribution lines 

(sec. 

168(e)(3)(E)(viii)) 

Fifteen-year MACRS recovery period and a class life of 

35 years is provided for natural gas distribution lines 

placed in service after April 11, 2005 and before January 

1, 2011 provided original use of the property begins with 

the taxpayer 

December 31, 2010 

Natural gas 

gathering lines 

(sec. 

168(e)(3)(C)(iv)) 

Seven-year MACRS recovery period and 14-year class 

life is provided for natural gas gathering pipelines. 

None 

Election to expense 

50 percent of 

qualified property 

used in refining 

liquid fuels 

(sec. 179C) 

Taxpayers may elect to expense 50 percent of the cost of 

qualified refinery property used for processing liquid fuel 

from crude oil or qualified fuels; remaining 50 percent is 

recovered under otherwise applicable rules. 

December 31, 2013 

Special expensing 

rule for capital 

costs incurred by 

small refiners to 

comply with EPA 

sulfur regulations 

(sec. 179B) 

A small business refiner may deduct 75 percent of the 

costs paid or incurred in complying with the Highway 

Diesel Fuel Sulfur Control requirement of the EPA. 

Costs must be paid or 

incurred on or before 

December 31, 2009 
12 

Summary of Fossil Fuel Capital Cost Recovery Provisions (cont’d)

 Description of Provision Expiration 

Deduction for 

tertiary injectants 

(sec. 193) 

Taxpayers engaged in petroleum extraction activities may 

generally deduct qualified tertiary injectant expenses used 

while applying a tertiary recovery method. 

None 

Election to expense 

intangible drilling 

costs (secs. 263(c) 

and 291) 

Taxpayers may elect to currently deduct intangible drilling 

costs (IDCs) paid or incurred with respect to the 

development of an oil or gas property located in the 

United States. For an integrated oil company that has 

elected to expense IDCs, 30 percent of the IDCs on 

productive wells must be capitalized and amortized over a 

60-month period. 

None 

Depletion 

(secs. 611-613A) 

 Depletion is available to any person having an 

economic interest in a producing oil and gas property. 

There are generally two types of depletion--cost and 

percentage depletion. Cost depletion is limited to the 

taxpayer’s basis in the property, whereas percentage 

depletion is not limited by the basis, but is subject to 

limitations based on net income derived from the 

property and taxable income. 

 Percentage depletion for producing oil and gas property 

(15 percent rate) is available only to independent 

producers and royalty owners. For marginal properties, 

the taxable income limitation is suspended for taxable 

years ending before January 1, 2010. 

 Percentage depletion is also available for coal and 

lignite (10 percent rate) and oil shale (15 percent rate). 

The percentage depletion deduction coal and lignite is 

generally reduced by an amount equal to 20 percent of 

the percentage depletion that exceeds the adjusted basis 

of the property. 

Suspension of taxable 

income limitation for 

marginal properties 

expires December 31, 

2009 
13 

H. Summary of Energy Credits Related to Fossil Fuels 

Eligible 

Activity Description Credit Amount Expiration 

Enhanced oil 

recovery 

(EOR) credit 

(sec. 43) 

 Credit for expenses associated with an 

EOR project 

 An EOR project is generally a project 

that involves the use of one or more 

tertiary recovery methods to increase 

the amount of recoverable domestic 

crude oil 

 15 percent of 

enhanced oil 

recovery costs 

 Currently 

phased-out 

None 

Marginal 

wells credit 

(sec. 45I) 

Production credit for marginal wells or 

wells that have an average daily production 

of not more than 25 barrels per day 

 $3-per-barrel 

credit (adjusted 

for inflation 

from 2004) for 

the production 

of crude oil 

from marginal 

wells 

 $0.50-per1,000-cubic-feet 

credit (adjusted 

for inflation 

from 2004) for 

the production 

of natural gas 

from a marginal 

wells 

 Currently 

phased-out 

None 

Indian coal 

credit 

(sec. 45) 

Production credit for coal produced at 

facilities placed in service before 2009 

that produce coal from reserves that on 

June 14, 2005 were owned by (or held in 

trust on behalf of) an Indian tribe 

 $1.50-per-ton 

production 

credit (adjusted 

for inflation 

from 2005) for 

2006 and 2007 

 $2-per-ton 

credit (adjust for 

inflation from 

2005) for 2008 

through 2012 

12/31/12 
14 

Summary of Energy Credits Related to Fossil Fuels (cont’d) 

Eligible 

Activity Description Credit Amount Expiration 

Refined coal 

credit (used 

to produce 

steam) 

(sec. 45) 

Production credit for refined coal, defined 

as a synthetic fuel produced from coal 

(including lignite) or high-carbon fly ash 

that when burned emits 20 percent less 

nitrogen oxide and 40 percent less sulfur 

dioxide or mercury compared to feedstock 

coal available in 2003 

 $4.375-per-ton 

production 

credit (adjusted 

for inflation 

from 1992) 

 Credit is 

available during 

the 10-year 

period from the 

date the facility 

was placed in 

service 

12/31/2009 

Refined coal 

credit (used 

as steel 

industry fuel) 

(sec. 45) 

Production credit for steel industry fuel, 

defined as a fuel produced through a 

process of liquefying coal waste sludge, 

distributing the liquefied product on coal, 

and using the resulting mixture as a 

feedstock for the manufacture of coke 

$2 (adjusted for 

inflation from 

1992) per barrel-ofoil equivalent 

 Generally, one 

year from 

facility placedin-service date 

or 12/31/2009 

 Facilities must 

be placed in 

service before 

1/1/2010 

Coke credit 

(sec. 45K) 

 Credit for the production of coke or 

coke gas (excluding petroleum-based 

coke or coke gas) 

 Amount of credit-eligible coke per 

facility is limited to 4,000 barrels per 

day 

$3 (adjusted for 

inflation from 

2004) per barrel-ofoil equivalent 

 Facilities must 

be placed in 

service by 

12/31/2009 

 Credit available 

for four years 

from placed-inservice date 
15 

Summary of Energy Credits Related to Fossil Fuels (cont’d) 

Eligible 

Activity Description Credit Amount Expiration 

Advanced 

coal project 

credit 

(sec. 48A) 

 Investment credit for projects that use 

integrated gasification combined cycle 

(IGCC) or other advanced coal-based 

electricity generation technologies 

 Credits are allocated by the Secretary 

 First round allocations are capped at 

$800 million for IGCC projects and 

$500 million for other projects 

 Second round allocations are capped at 

$1.25 billion 

 Second round projects must generally 

sequester 65 percent of total CO2

emissions 

 20 percent for 

first round 

IGCC projects 

 15 percent for 

other first round 

projects 

 30 percent for 

second round 

projects 

None 

(other than the 

credit allocation 

limitation) 

Gasification 

credit 

(sec. 48B) 

 Investment credit for qualified projects 

that use gasification technology 

 Qualified projects convert coal, 

petroleum residue, biomass, or other 

materials recovered for their energy 

content into a synthesis gas for direct 

use or subsequent chemical or physical 

conversion 

 Credits are allocated by the Secretary 

 First round allocations are capped at 

$350 million 

 Second round allocations are capped at 

$250 million 

 First round projects are generally 

limited to industrial applications; 

second round projects include projects 

designed to produce motor fuels 

 Second round projects must generally 

sequester 65 percent of total CO2

emissions 

 20 percent for 

first round 

 30 percent for 

second round 

None 

(other than the 

credit allocation 

limitation) 
16 

I. Summary of Other Energy Provisions 

Eligible Activity Description Credit Amount for 

2008 Expiration 

Carbon dioxide 

sequestration credit 

(sec. 45Q) 

 Credit for the 

sequestration of 

industrial source carbon 

dioxide produced at 

qualified U.S. facilities 

 Qualified facilities must 

capture at least 500,000 

metric tons of CO2 per 

year. 

 $10 for CO2 used as 

a tertiary injectant 

and then 

permanently 

sequestered 

 $20 for CO2 

permanently 

sequestered without 

being first used as a 

tertiary injectant 

End of the 

year in which 

the Secretary 

determines 

that 75 million 

tons of CO2 

have been 

captured and 

sequestered 

Energy research credit 

(sec. 41) 

 Credit for payments 

made to energy 

research consortia for 

qualified energy 

research 

 Includes research 

related to fossil fuels as 

well as to renewable 

energy technologies 

20 percent of qualified 

expenses 

12/31/2009 

Advanced energy property 

credit (sec. 48C) 

 Investment credit for 

property used in a 

qualified advanced 

energy manufacturing 

project 

 Credits are allocated by 

the Secretary 

 Up to $2.3 billion of 

credits may be allocated 

30 percent of qualified 

investment expenses 

None other 

than the credit 

allocation 

limitation 

Advanced nuclear power 

production credit (sec. 45J) 

 Credit for production of 

nuclear power from 

new facilities that use 

modern designs and 

have received an 

allocation from the 

Secretary 

 Secretary may allocate 

up 6,000 megawatts of 

credit-eligible capacity 

1.8 cents per kilowatthour for the eight-year 

period starting when the 

facility was placed in 

service 

Qualified 

facilities must 

have been 

placed in 

service by 

12/31/2020 
17 

Summary of Other Energy Provisions (cont’d) 

Eligible Activity Description Credit Amount for 

2008 Expiration 

Passive loss rules for 

working interests in oil and 

gas property (sec. 469) 

 Passive activity loss 

rules not applicable to 

working interest in any 

oil or gas property that 

taxpayer holds directly 

or indirectly through an 

entity that does not 

limit the taxpayer’s 

liability 

 Losses and credits from 

such interests, in 

general, may offset 

income from other 

activities of taxpayer 

N/A None 

Nuclear decommissioning 

costs (sec. 468A) 

 Current tax deduction 

allowed for 

contributions to 

qualified nuclear 

decommissioning fund 

at election of taxpayer 

 Income of fund taxed at 

reduced rate of 20 

percent 

N/A None 

Reduced tax for diesel-water 

fuel emulsion (secs. 

4081(a)(2)(D), 4081(c), and 

6427(m)) 

 Diesel fuel tax rate of 

24.3 cents per gallon is 

reduced to 19.7 cents 

per gallon for dieselwater fuel emulsion to 

reflect the reduced Btu 

content per gallon 

resulting from the 

water. 

 Refund of the 

difference between the 

two rates is available to 

the extent tax-paid 

diesel is used to 

produce a qualifying 

emulsion diesel fuel. 

N/A None 
18 

Summary of Other Energy Provisions (cont’d)

Eligible Activity Description Credit Amount for 

2008 Expiration 

Certain publicly treated 

partnerships treated as 

corporations (secs. 7704 and 

851) 

 General rule that a 

publicly traded 

partnership is taxed as a 

corporation is not 

applicable if 90 percent 

of gross income is 

interest, dividends, real 

property rents, or 

certain other types of 

qualifying income 

 Other types of 

qualifying income 

includes income and 

gains from certain 

activities with respect 

to natural resources 

N/A None 

Energy conservation 

subsidies provided by public 

utilities (sec. 136) 

 Energy conservation 

subsidies provided by 

public utilities are 

excluded from gross 

income 

N/A None 

Five-Year carryback of net 

operating losses for certain 

electric utility companies 

(sec. 172(b)(1)(I)) 

 A portion of net 

operating losses arising 

in 2003 - 2005 for 

certain electric utility 

companies may be 

carried back for 5 years 

N/A December 31, 

2008 

Deferral of Gains from the 

Sale of Electric 

Transmission Property 

(sec. 451(i)) 

 A taxpayer may elect to 

recognize gain ratably 

over an eight year 

period for gains on 

disposition of certain 

electric transmission 

property 

N/A December 31, 

2009 
19 

J. Summary of Energy-Related Bond Provisions 

Type of Bond Description 

Clean Renewable 

Energy Bonds 

(“CREBs”) 

(sec. 54) 

 Tax credit bond. 

 CREBs are defined as any bond if the proceeds from the issuance of such 

bonds are used to finance facilities that qualify for the tax credit under section 

45 (other than Indian coal production facilities). 

 Credit rate is rate that permits issuance of CREBs without discount and interest 

cost to the qualified issuer. 

 Qualified issuers include electrical cooperatives, clean renewable energy bond 

lenders, and State and local governments (including Indian tribes).

 Volume limited and allocated by the Secretary of the Treasury.

New CREBs 

(sec. 54C) 

 Tax credit bond. 

 New CREBs may be issued to finance “qualified renewable energy facilities.” 

Qualified renewable energy facilities are facilities that: (1) qualify for the tax 

credit under section 45 (other than Indian coal and refined coal production 

facilities). 

 Credit rate is 70 percent of the rate that permits issuance of bonds without 

discount and interest cost to the issuer. 

 Qualified issuers include electrical cooperatives, clean renewable energy bond 

lenders, public power providers, State and local governments (including Indian 

tribes), and not-for-profit electric utilities which have a loan or loan guarantee 

under the Rural Electrification Act.

 Volume limited and allocated by the Secretary of the Treasury.

Qualified Energy 

Conservation Tax 

Credit Bonds 

(“QECs”) 

(sec. 54D) 

 Tax credit bond. 

 Bond issuance must be used for “qualified conservation purposes” (described 

in detail in section II.B.6 of this document). 

 Credit rate is 70 percent of the rate that permits issuance of bonds without 

discount and interest cost to the issuer.

 Volume limited and allocated by the Secretary of the Treasury.

Safe Harbor from 

arbitrage rules for 

prepaid natural gas 

(sec. 148) 

 Allows tax-exempt bonds to be used to finance prepaid natural gas contracts 

without application of the otherwise applicable arbitrage rules. 
20 

Summary of Energy-Related Bond Provisions (cont’d) 

Type of Bond Description 

Tax-exempt bonds 

for certain public 

energy - related 

projects (sec. 103) 

 Tax-exempt bond 

 May be used for financing government-owned and operated electrical and gas 

powered generation, transmission and distribution facilities 

 Not subject to any volume caps

Tax-exempt bonds 

for certain public 

private energy - 

related projects 

(secs. 141, and 142) 

 Tax-exempt bond 

 May be used for financing certain exempt facilities including privately owned 

and/or operated utility facilities (sewage, water, solid waste disposal, and local 

district heating and cooling facilities, certain private electric and gas facilities, 

and hydroelectric dam enhancements); qualified green building and sustainable 

design projects 

 Generally subject to private activity volume cap
21 

II. DESCRIPTION OF PRESENT LAW 

A. Tax Provisions Relating to Renewable Energy 

1. Credit for alternative fuel vehicle refueling property (sec. 30C) 

Present Law

Taxpayers may claim a 30-percent credit for the cost of installing qualified clean-fuel 

vehicle refueling property to be used in a trade or business of the taxpayer or installed at the 

principal residence of the taxpayer.2

 The credit may not exceed $30,000 per taxable year per 

location, in the case of qualified refueling property used in a trade or business and $1,000 per 

taxable year per location, in the case of qualified refueling property installed on property which 

is used as a principal residence. 

For property placed in service in 2009 or 2010, the maximum credit available for 

business property is increased to $200,000 for qualified hydrogen refueling property and to 

$50,000 for other qualified refueling property. For nonbusiness property, the maximum credit is 

increased to $2,000 for refueling property other than hydrogen refueling property. In addition, 

during these years, the credit rate is increased from 30 percent to 50 percent for refueling 

property other than hydrogen refueling property. 

Qualified refueling property is property (not including a building or its structural 

components) for the storage or dispensing of a clean-burning fuel or electricity into the fuel tank 

or battery of a motor vehicle propelled by such fuel or electricity, but only if the storage or 

dispensing of the fuel or electricity is at the point of delivery into the fuel tank or battery of the 

motor vehicle. The use of such property must begin with the taxpayer. 

Clean-burning fuels are any fuel at least 85 percent of the volume of which consists of 

ethanol, natural gas, compressed natural gas, liquefied natural gas, liquefied petroleum gas, or 

hydrogen. In addition, any mixture of biodiesel and diesel fuel, determined without regard to 

any use of kerosene and containing at least 20 percent biodiesel, qualifies as a clean fuel. 

Credits for qualified refueling property used in a trade or business are part of the general 

business credit and may be carried back for one year and forward for 20 years. Credits for 

residential qualified refueling property cannot exceed for any taxable year the difference between 

the taxpayer’s regular tax (reduced by certain other credits) and the taxpayer’s tentative 

minimum tax. Generally, in the case of qualified refueling property sold to a tax-exempt entity, 

the taxpayer selling the property may claim the credit. 

A taxpayer’s basis in qualified refueling property is reduced by the amount of the credit. 

In addition, no credit is available for property used outside the United States or for which an 

election to expense has been made under section 179. 

 2

 Sec. 30C. 
22 

The credit is available for property placed in service after December 31, 2005, and 

(except in the case of hydrogen refueling property) before January 1, 2011. In the case of 

hydrogen refueling property, the property must be placed in service before January 1, 2015. 

2. Incentives for alcohol, cellulosic biofuel, biodiesel, renewable diesel, and certain 

alternative fuels (secs. 40, 40A, 6426, and 6427(e)) 

Overview

The Code provides per-gallon incentives relating to the following qualified fuels: alcohol 

(including ethanol), biodiesel (including agri-biodiesel), renewable diesel, and certain alternative 

fuels.3

 The incentives may be taken as an income tax credit, excise tax credit or payment. The 

provisions are coordinated so that a gallon of qualified fuel is only taken into account once. If 

the qualified fuel is part of a qualified fuel mixture, the incentives apply only to the amount of 

qualified fuel in the mixture. The Code also provides an income tax credit for qualified 

cellulosic biofuel production. 

For alcohol, other than ethanol, the amount of the credit generally is 60 cents per gallon.4

 

For ethanol, the credit is generally 45 cents per gallon, with an extra 10 cents per gallon available 

for small ethanol producers. The alcohol incentives expire after December 31, 2010. The 

amount of the credit is $1.00 per gallon for biodiesel, agri-biodiesel and renewable diesel. An 

extra 10 cents per gallon is available for small producers of agri-biodiesel. The biodiesel, agribiodiesel and renewable diesel incentives expire after December 31, 2009. The credit amount for 

alternative fuels is 50 cents per gallon. The incentives for alternative fuels expire after 

December 31, 2009 (after September 30, 2014, in the case of liquefied hydrogen). For cellulosic 

biofuel, the provision is applicable to qualified cellulosic biofuel production through December 

31, 2012. 

Fuel that is produced outside the United States for use as a fuel outside the United States 

is ineligible for the per-gallon tax incentives relating to alcohol, biodiesel, renewable diesel, and 

alternative fuel. For example, fuel in the following situations is ineligible for incentives: (1) 

biodiesel, which is not in a mixture, that is both produced and used outside the United States, (2) 

foreign-produced biodiesel that is used to make a qualified mixture outside of the United States 

for foreign use, and (3) foreign-produced biodiesel that is used to make a qualified mixture in the 

United States that is then exported for foreign use. For cellulosic biofuel, the fuel must be both 

produced in the United States and used as fuel in the United States. 

 3

 See secs. 40, 40A, 6426, and 6427(e). In addition, the payments authorized under section 

6427(e) of the Code for alcohol fuel mixtures, biodiesel fuel mixtures, renewable diesel fuel mixtures, 

alternative fuel mixtures and alternative fuel, may be taken as a refundable income tax credit pursuant to 

section 34 and section 6401(b)(1) of the Code. The section 34 income tax credit is not available for any 

amount for which a timely claim has been filed under section 6427. 

4

 For the section 40 income tax credit, there is a smaller credit amount for alcohol with a proof of 

at least 150 but less than 190. 
23 

Alcohol made from petroleum, natural gas, or coal does not qualify for the incentives 

mentioned above. For fuel alcohol that is made from natural gas, the Code provides a reduced 

rate of tax. This incentive expires September 30, 2011. The reduced rate of tax for alcohol made 

from coal expired January 1, 2009. 

Alcohol and cellulosic biofuel

Sections 40, 6426 and 6427(e) provide per-gallon tax incentives for the sale, use and 

production of alcohol fuel and alcohol fuel mixtures. The incentives for alcohol generally do not 

apply after December 31, 2010. For cellulosic biofuel (discussed infra), the incentive is 

unavailable after December 31, 2012. 

“Alcohol” includes methanol and ethanol, and the alcohol gallon equivalent of ethyl 

tertiary butyl ether, or other ethers produced from such alcohol. It does not include alcohol 

produced from petroleum, natural gas, or coal, or any alcohol with a proof of less than 150 (190 

proof for purposes of the credit taken under 6426 or payment under section 6427). Denaturants 

(additives that make the alcohol unfit for human consumption) are disregarded for purposes of 

determining proof. However, denaturants are taken into account in determining the volume of 

alcohol eligible for the per-gallon incentive. In calculating alcohol volume, denaturants cannot 

exceed two percent of volume.5

 

 The section 40 alcohol fuels credit is an income tax credit comprised of four 

components: (1) the alcohol mixture credit, (2) the alcohol credit, (3) the small ethanol producer 

credit, and (4) the cellulosic biofuel producer credit. Sections 6426 and 6427(e) pertain to 

alcohol fuel mixtures only. 

Alcohol mixture credits and payments

The alcohol fuel mixture credit may be taken as part of the section 40 income tax credit, 

the section 6426 excise tax credit or as a payment under section 6427. For section 40, an alcohol 

fuel mixture is a mixture of alcohol and gasoline or alcohol and a special fuel. Since the excise 

tax credit is taken against the liability for taxable fuels (gasoline, kerosene, or diesel), for 

purposes of the excise tax payments and credits, an alcohol fuel mixture is a mixture of alcohol 

and a taxable fuel. 

 5

 Before January 1, 2009, the Code permitted the volume of alcohol eligible for the credit to 

include up to five percent denaturants. Gasoline is often used as denaturant. Section 15332 of the Food, 

Conservation and Energy Act of 2008 (Pub. L. No 110-234) reduced allowable denaturants from five 

percent to two percent. Under Alcohol, Tobacco Tax and Trade Bureau regulations (27 C.F.R. sec. 

19.1005) for alcohol to be eligible for withdrawal as fuel alcohol, denaturants included in the volume of 

the fuel alcohol must exceed 1.96 percent of the volume of the fuel alcohol. Because of comments from 

the public about the ability to accurately measure the volume of denaturants in alcohol, Notice 2009-6, 

2009-3 I.R.B. (2009), provides a safe harbor and transitional rule to implement the two-percent limitation. 

The IRS will treat denaturants as not clearly exceeding the two-percent limitation unless there is clear 

evidence establishing that the denaturants exceed 2.5 percent of volume (including denaturants). The safe 

harbor is available only if no more than two percent of the alcohol’s volume is disregarded under the rule 

providing that proof is determined without regard to added denaturants. 
24 

The fuel must be either sold for use as a fuel to another person or used as fuel in the 

mixture producer’s trade or business. The addition of denaturants is not the production of a 

mixture. The credit is allowed only for the gallons of alcohol used to produce the mixture. For 

alcohol that is ethanol, the amount of the incentive is 45 cents per gallon. For other alcohol, the 

incentive is 60 cents per gallon. 

The alcohol mixture credit is most often taken as an excise tax credit or payment. 

Persons who blend alcohol with gasoline, diesel fuel, or kerosene to produce an alcohol fuel 

mixture must pay tax on the volume of alcohol in the mixture when the mixture is sold or 

removed. The alcohol fuel mixture credit must first be taken to reduce excise tax liability for 

gasoline, diesel fuel or kerosene. Any excess credit may be taken as a payment or income tax 

credit. 

Alcohol credit (straight or “neat” alcohol)

The second component of the section 40 income tax credit is the alcohol credit. The 

credit is available for alcohol (not in a mixture) that is either (1) used as a fuel in the taxpayer’s 

trade or business, or (2) sold at retail and placed in the fuel tank of the retail buyer. The credit 

cannot be claimed for alcohol bought at retail, even if the buyer uses it as a fuel in a trade or 

business. This credit is not available as an excise tax credit or payment. 

Small ethanol producer credit

The third component of the section 40 income tax credit is the small ethanol producer 

credit. It is in addition to the credits described above and is an extra 10 cents per gallon available 

for up to 15 million gallons of qualified ethanol fuel production for any tax year. The 15 million 

gallon limitation is waived for ethanol that is cellulosic ethanol. The credit is available to 

eligible small ethanol producers, defined as producers who have an annual productive capacity of 

not more than 60 million gallons of any type of alcohol. Qualified ethanol fuel production is 

ethanol produced and sold by such producer to another person (a) for use by such other person in 

the production of a qualified alcohol fuel mixture in such person’s trade or business (other than 

casual off-farm production), (b) for use by such other person as a fuel in a trade or business, or 

(c) who sells such ethanol at retail to another person and places such ethanol in the fuel tank of 

such other person. Qualified ethanol fuel production also includes use or sale by the producer 

for any purpose described in (a), (b), or (c). A cooperative may pass through the small ethanol 

producer credit to its patrons. 

The small ethanol producer credit is not available as an excise tax credit or payment. 

Cellulosic biofuel producer credit

Section 15332 of the Food, Conservation, and Energy Act of 2008 (Pub. L. No 110-234) 

added a new component to section 40 of the Code, the “cellulosic biofuel producer credit.” This 

credit is a nonrefundable income tax credit for each gallon of qualified cellulosic fuel production 

of the producer for the taxable year. The amount of the credit per gallon is $1.01, except in the 

case of cellulosic biofuel that is alcohol. In the case of cellulosic biofuel that is alcohol, the 

$1.01 credit amount is reduced by (1) the credit amount applicable for such alcohol under the 

alcohol mixture credit as in effect at the time cellulosic biofuel is produced and (2) in the case of 
25 

cellulosic biofuel that is also ethanol, the credit amount for small ethanol producers as in effect at 

the time the cellulosic biofuel fuel is produced. The reduction applies regardless of whether the 

producer claims the alcohol mixture credit or small ethanol producer credit with respect to the 

cellulosic alcohol. When the alcohol mixture credit and small ethanol producer credit expire 

after December 31, 2010, cellulosic biofuel will receive the $1.01 without reduction. 

“Qualified cellulosic biofuel production” is any cellulosic biofuel which is produced by 

the taxpayer and which is (1) sold by the taxpayer to another person (a) for use by such other 

person in the production of a qualified biofuel fuel mixture in such person’s trade or business 

(other than casual off-farm production), (b) for use by such other person as a fuel in a trade or 

business, or, (c) who sells such biofuel at retail to another person and places such biofuel in the 

fuel tank of such other person; or (2) used by the producer for any purpose described in (a), (b), 

or (c). 

“Cellulosic biofuel” means any liquid fuel that (1) is produced in the United States and 

used as fuel in the United States,6

 (2) is derived from any lignocellulosic or hemicellulosic matter 

that is available on a renewable or recurring basis and (3) meets the registration requirements for 

fuels and fuel additives established by the Environmental Protection Agency (“EPA”) under 

section 211 of the Clean Air Act. Thus, to qualify for the credit the fuel must be approved by the 

Environmental Protection Agency. Cellulosic biofuel does not include any alcohol with a proof 

of less than 150. 

A “qualified cellulosic biofuel mixture” is a mixture of cellulosic biofuel and a special 

fuel or of cellulosic biofuel and gasoline, which is sold by the person producing such mixture to 

any person for use as a fuel, or is used as a fuel by the person producing such mixture. The term 

“special fuel” includes any liquid fuel (other than gasoline) which is suitable for use in an 

internal combustion engine. 

The cellulosic biofuel producer credit terminates on December 31, 2012. The cellulosic 

biofuel producer credit cannot be claimed unless the taxpayer is registered with the IRS as a 

producer of cellulosic biofuel. 

Cellulosic biofuel eligible for the section 40 credit cannot qualify as biodiesel, renewable 

diesel, or alternative fuel for purposes of the income tax credit, excise tax credit, or payment 

provisions relating to those fuels.7

Alcohol produced from coal and natural gas

As noted above, the alcohol incentives discussed above do not apply to alcohol produced 

from petroleum, natural gas, or coal. There is a reduced rate of tax for fuel alcohol produced 

from natural gas. The reduced rate of tax for fuel alcohol produced from coal has expired. 

 6

 For this purpose, “United States” includes any possession of the United States. 

7

 See secs. 40A(d)(1), 40A(f)(3), 6426(h). 
26 

Reduced rate of tax for alcohol fuels produced from natural gas

A reduced rate of fuel tax is provided for “partially exempt methanol or ethanol fuel.” 

The term “partially exempt methanol or ethanol fuel” means any liquid at least 85 percent of 

which consists of methanol, ethanol or other alcohol (including methanol and ethanol) produced 

from natural gas. Partially exempt methanol (or other alcohol) is taxed at 9.15 cents per gallon. 

Partially exempt ethanol is taxed at 11.3 cents per gallon. After September 30, 2011, these rates 

drop to 2.15 cents per gallon and 4.3 cents per gallon, respectively. 

Reduced rate of tax for alcohol fuels produced from coal

A reduced rate of fuel tax was also provided for “qualified methanol and ethanol fuel.” 

The term “qualified methanol or ethanol fuel” means any liquid at least 85 percent of which 

consists of methanol, ethanol, or other alcohol produced from coal (including peat). Qualified 

ethanol was taxed at 13.25 cents per gallon. Qualified methanol was taxed at 12.35 cents per 

gallon. The incentive expired January 1, 2009. 

Biodiesel

The Code provides an income tax credit for biodiesel fuels (the “biodiesel fuels credit”).8 

The biodiesel fuels credit is the sum of three credits: (1) the biodiesel mixture credit, (2) the 

biodiesel credit, and (3) the small agri-biodiesel producer credit. The biodiesel fuels credit is 

treated as a general business credit. The amount of the biodiesel fuels credit is includable in 

gross income. The biodiesel fuels credit is coordinated to take into account benefits from the 

biodiesel excise tax credit and payment provisions discussed below. The credit does not apply to 

fuel sold or used after December 31, 2009. 

Biodiesel is monoalkyl esters of long chain fatty acids derived from plant or animal 

matter that meet (1) the registration requirements established by the EPA under section 211 of 

the Clean Air Act (42 U.S.C. sec. 7545) and (2) the requirements of the American Society of 

Testing and Materials (“ASTM”) D6751. Agri-biodiesel is biodiesel derived solely from virgin 

oils including oils from corn, soybeans, sunflower seeds, cottonseeds, canola, crambe, rapeseeds, 

safflowers, flaxseeds, rice bran, mustard seeds, camelina, or animal fats. 

Biodiesel may be taken into account for purposes of the credit only if the taxpayer 

obtains a certification (in such form and manner as prescribed by the Secretary) from the 

producer or importer of the biodiesel that identifies the product produced and the percentage of 

biodiesel and agri-biodiesel in the product. 

Biodiesel mixture credit

The biodiesel mixture credit is $1.00 for each gallon of biodiesel (including agribiodiesel) used by the taxpayer in the production of a qualified biodiesel mixture. A qualified 

biodiesel mixture is a mixture of biodiesel and diesel fuel that is (1) sold by the taxpayer 

 8

 Sec. 40A. 
27 

producing such mixture to any person for use as a fuel, or (2) used as a fuel by the taxpayer 

producing such mixture. The sale or use must be in the trade or business of the taxpayer and is 

to be taken into account for the taxable year in which such sale or use occurs. No credit is 

allowed with respect to any casual off-farm production of a qualified biodiesel mixture. 

Per IRS guidance a mixture need only contain 1/10th of one percent of diesel fuel to be a 

qualified mixture. Thus, a qualified biodiesel mixture can contain 99.9 percent biodiesel and 0.1 

percent diesel fuel. 

Biodiesel credit (straight biodiesel)

The biodiesel credit is $1.00 for each gallon of biodiesel that is not in a mixture with 

diesel fuel (100 percent biodiesel or B-100) and which during the taxable year is (1) used by the 

taxpayer as a fuel in a trade or business or (2) sold by the taxpayer at retail to a person and 

placed in the fuel tank of such person’s vehicle. 

Small agri-biodiesel producer credit

The Code provides a small agri-biodiesel producer income tax credit, in addition to the 

biodiesel and biodiesel fuel mixture credits. The credit is a 10-cents-per-gallon credit for up to 

15 million gallons of agri-biodiesel produced by small producers, defined generally as persons 

whose agri-biodiesel production capacity does not exceed 60 million gallons per year. The agribiodiesel must (1) be sold by such producer to another person (a) for use by such other person in 

the production of a qualified biodiesel mixture in such person’s trade or business (other than 

casual off-farm production), (b) for use by such other person as a fuel in a trade or business, or, 

(c) who sells such agri-biodiesel at retail to another person and places such agri-biodiesel in the 

fuel tank of such other person; or (2) used by the producer for any purpose described in (a), (b), 

or (c). 

Biodiesel mixture excise tax credit

The Code also provides an excise tax credit for biodiesel mixtures.9

 The credit is $1.00 

for each gallon of biodiesel used by the taxpayer in producing a biodiesel mixture for sale or use 

in a trade or business of the taxpayer. A biodiesel mixture is a mixture of biodiesel and diesel 

fuel that (1) is sold by the taxpayer producing such mixture to any person for use as a fuel or (2) 

is used as a fuel by the taxpayer producing such mixture. No credit is allowed unless the 

taxpayer obtains a certification (in such form and manner as prescribed by the Secretary) from 

the producer of the biodiesel that identifies the product produced and the percentage of biodiesel 

and agri-biodiesel in the product.10 

 9

 Sec. 6426(c). 

10 Sec. 6426(c)(4). 
28 

The credit is not available for any sale or use for any period after December 31, 2009. 

This excise tax credit is coordinated with the income tax credit for biodiesel such that credit for 

the same biodiesel cannot be claimed for both income and excise tax purposes. 

Payments with respect to biodiesel fuel mixtures 

If any person produces a biodiesel fuel mixture in such person’s trade or business, the 

Secretary is to pay such person an amount equal to the biodiesel mixture credit.11 The biodiesel 

fuel mixture credit must first be taken against tax liability for taxable fuels. To the extent the 

biodiesel fuel mixture credit exceeds such tax liability, the excess may be received as a payment. 

Thus, if the person has no section 4081 liability, the credit is refundable. The Secretary is not 

required to make payments with respect to biodiesel fuel mixtures sold or used after December 

31, 2009. 

Renewable diesel

“Renewable diesel” is liquid fuel that (1) is derived from biomass (as defined in section 

45K(c)(3)), (2) meets the registration requirements for fuels and fuel additives established by the 

EPA under section 211 of the Clean Air Act, and (3) meets the requirements of the ASTM D975 

or D396, or equivalent standard established by the Secretary. ASTM D975 provides standards 

for diesel fuel suitable for use in diesel engines. ASTM D396 provides standards for fuel oil 

intended for use in fuel-oil burning equipment, such as furnaces. Renewable diesel also includes 

fuel derived from biomass that meets the requirements of a Department of Defense specification 

for military jet fuel or an ASTM for aviation turbine fuel. 

For purposes of the Code, renewable diesel is generally treated the same as biodiesel. In 

the case of renewable diesel that is aviation fuel, kerosene is treated as though it were diesel fuel 

for purposes of a qualified renewable diesel mixture. Like biodiesel, the incentive may be taken 

as an income tax credit, an excise tax credit, or as a payment from the Secretary.12 The incentive 

for renewable diesel is $1.00 per gallon. There is no small producer credit for renewable diesel. 

The incentives for renewable diesel expire after December 31, 2009. 

Alternative fuel excise tax credits and payments

The Code provides two per-gallon excise tax credits with respect to alternative fuel, the 

alternative fuel credit, and the alternative fuel mixture credit. For this purpose, the term 

“alternative fuel” means liquefied petroleum gas, P Series fuels (as defined by the Secretary of 

Energy under 42 U.S.C. sec. 13211(2)), compressed or liquefied natural gas, liquefied hydrogen, 

liquid fuel derived from coal through the Fischer-Tropsch process (“coal-to-liquids”), 

compressed or liquified gas derived from biomass, or liquid fuel derived from biomass. Such 

term does not include ethanol, methanol, or biodiesel. 

 11 Sec. 6427(e). 

12 Secs. 40A(f), 6426(c), and 6427(e). 
29 

For coal-to-liquids produced after September 30, 2009 through December 30, 2009, the 

fuel must be certified as having been derived from coal produced at a gasification facility that 

separates and sequesters 50 percent of such facility’s total carbon dioxide emissions. The 

sequestration percentage increases to 75 percent for fuel produced after December 30, 2009. 

The alternative fuel credit is allowed against section 4041 liability, and the alternative 

fuel mixture credit is allowed against section 4081 liability. Neither credit is allowed unless the 

taxpayer is registered with the Secretary. The alternative fuel credit is 50 cents per gallon of 

alternative fuel or gasoline gallon equivalents13 of nonliquid alternative fuel sold by the taxpayer 

for use as a motor fuel in a motor vehicle or motorboat, sold for use in aviation or so used by the 

taxpayer. 

The alternative fuel mixture credit is 50 cents per gallon of alternative fuel used in 

producing an alternative fuel mixture for sale or use in a trade or business of the taxpayer. An 

“alternative fuel mixture” is a mixture of alternative fuel and taxable fuel that contains at least 

1/10 of one percent taxable fuel.14 The mixture must be sold by the taxpayer producing such 

mixture to any person for use as a fuel, or used by the taxpayer producing the mixture as a fuel. 

The credits generally expire after December 31, 2009. 

A person may file a claim for payment equal to the amount of the alternative fuel credit 

and alternative fuel mixture credits. These payment provisions generally also expire after 

December 31, 2009. With respect to liquefied hydrogen, the credit and payment provisions 

expire after September 30, 2014. The alternative fuel credit and alternative fuel mixture credit 

must first be applied to excise tax liability for special and alternative fuels, and any excess credit 

may be taken as a payment. 

 13 “Gasoline gallon equivalent” means, with respect to any nonliquid alternative fuel (for 

example, compressed natural gas), the amount of such fuel having a Btu (British thermal unit) content of 

124,800 (higher heating value). 

14 See Internal Revenue Service, Notice 2006-92, Alternative Fuel, Alternative Fuel Mixtures; 

Blood Collector Organizations, 2006-43 I.R.B. 774 (October 23, 2006). Recent alternative fuel mixture 

claims for the burning of black liquor (a byproduct of the manufacturing of pulp and paper) and diesel 

fuel in recovery boilers have highlighted the fact that the fuel mixture credits are not limited to 

transportation uses, and that there is no upper limit on the dollar amount that may be claimed. See, 

International Paper, News Release: International Paper Provides Update on Alternative Fuel Credits

(March 24, 2009); Steve Mufson, Washington Post, Papermakers Dig Deep in Highway Bill to Hit Gold

(March 28, 2009 at p. D.1); Rebecca Penty, New Brunswick Business Journal, Canada at a 

Disadvantage: Forestry Industry Contends Credits are Subsidies that Allow U.S. Firms to Better 

Compete (April 3, 2009 at p. B.1); and Jad Mouawad and Clifford Krauss, The New York Times, 

Lawmakers May Limit Paper Mills’ Windfall (April 18, 2009).
30 

3. Renewable electricity production credit (sec. 45) 

In general

An income tax credit is allowed for the production of electricity from qualified energy 

resources at qualified facilities (the “renewable electricity production credit”).15 Qualified 

energy resources comprise wind, closed-loop biomass, open-loop biomass, geothermal energy, 

solar energy, small irrigation power, municipal solid waste, qualified hydropower production, 

and marine and hydrokinetic renewable energy. Qualified facilities are, generally, facilities that 

generate electricity using qualified energy resources. To be eligible for the credit, electricity 

produced from qualified energy resources at qualified facilities must be sold by the taxpayer to 

an unrelated person. 

Credit amounts and credit period

In general

The base amount of the electricity production credit is 1.5 cents (indexed annually for 

inflation) per kilowatt-hour of electricity produced. The amount of the credit was 2.1 cents per 

kilowatt-hour for 2008. A taxpayer may generally claim a credit during the 10-year period 

commencing with the date the qualified facility is placed in service. The credit is reduced for 

grants, tax-exempt bonds, subsidized energy financing, and other credits. 

Credit phaseout

The amount of credit a taxpayer may claim is phased out as the market price of electricity 

exceeds certain threshold levels. The electricity production credit is reduced over a 3-cent 

phaseout range to the extent the annual average contract price per kilowatt-hour of electricity 

sold in the prior year from the same qualified energy resource exceeds 8 cents (adjusted for 

inflation; 11.8 cents for 2008). 

Reduced credit periods and credit amounts

Generally, in the case of open-loop biomass facilities (including agricultural livestock 

waste nutrient facilities), geothermal energy facilities, solar energy facilities, small irrigation 

power facilities, landfill gas facilities, and trash combustion facilities placed in service before 

August 8, 2005, the 10-year credit period is reduced to five years, commencing on the date the 

facility was originally placed in service. However, for qualified open-loop biomass facilities 

(other than a facility described in section 45(d)(3)(A)(i) that uses agricultural livestock waste 

nutrients) placed in service before October 22, 2004, the five-year period commences on 

January 1, 2005. In the case of a closed-loop biomass facility modified to co-fire with coal, to 

 15 Sec. 45. In addition to the renewable electricity production credit, section 45 also provides 

income tax credits for the production of Indian coal and refined coal at qualified facilities. A grant 

program is also available for 2009 and 2010 allowing taxpayers to apply for a thirty-percent grant in lieu 

of the renewable electricity production credit. 
31 

co-fire with other biomass, or to co-fire with coal and other biomass, the credit period begins no 

earlier than October 22, 2004. 

In the case of open-loop biomass facilities (including agricultural livestock waste nutrient 

facilities), small irrigation power facilities, landfill gas facilities, trash combustion facilities, and 

qualified hydropower facilities, the otherwise allowable credit amount is 0.75 cent per kilowatthour, indexed for inflation measured after 1992 (1 cent per kilowatt-hour for 2008). 

Other limitations on credit claimants and credit amounts

In general, to claim the credit, a taxpayer must own the qualified facility and sell the 

electricity produced by the facility to an unrelated party. A lessee or operator may claim the 

credit in lieu of the owner of the qualifying facility in the case of qualifying open-loop biomass 

facilities and in the case of closed-loop biomass facilities modified to co-fire with coal, to co-fire 

with other biomass, or to co-fire with coal and other biomass. In the case of a poultry waste 

facility, the taxpayer may claim the credit as a lessee or operator of a facility owned by a 

governmental unit. 

For all qualifying facilities, other than closed-loop biomass facilities modified to co-fire 

with coal, to co-fire with other biomass, or to co-fire with coal and other biomass, the amount of 

credit a taxpayer may claim is reduced by reason of grants, tax-exempt bonds, subsidized energy 

financing, and other credits, but the reduction cannot exceed 50 percent of the otherwise 

allowable credit. In the case of closed-loop biomass facilities modified to co-fire with coal, to 

co-fire with other biomass, or to co-fire with coal and other biomass, there is no reduction in 

credit by reason of grants, tax-exempt bonds, subsidized energy financing, and other credits. 

The credit for electricity produced from renewable resources is a component of the 

general business credit.16 Generally, the general business credit for any taxable year may not 

exceed the amount by which the taxpayer’s net income tax exceeds the greater of the tentative 

minimum tax or 25 percent of so much of the net regular tax liability as exceeds $25,000. 

However, this limitation does not apply to section 45 credits for electricity or refined coal 

produced from a facility (placed in service after October 22, 2004) during the first four years of 

production beginning on the date the facility is placed in service. 17 Excess credits may be 

carried back one year and forward up to 20 years. 

Qualified facilities

Wind energy facility

A wind energy facility is a facility that uses wind to produce electricity. To be a qualified 

facility, a wind energy facility must be placed in service after December 31, 1993, and before 

January 1, 2013. 

 16 Sec. 38(b)(8). 

17 Sec. 38(c)(4)(B)(ii). 
32 

Closed-loop biomass facility

A closed-loop biomass facility is a facility that uses any organic material from a plant 

that is planted exclusively for the purpose of being used at a qualifying facility to produce 

electricity. In addition, a facility can be a closed-loop biomass facility if it is a facility that is 

modified to use closed-loop biomass to co-fire with coal, with other biomass, or with both coal 

and other biomass, but only if the modification is approved under the Biomass Power for Rural 

Development Programs or is part of a pilot project of the Commodity Credit Corporation. 

To be a qualified facility, a closed-loop biomass facility must be placed in service after 

December 31, 1992, and before January 1, 2014. In the case of a facility using closed-loop 

biomass but also co-firing the closed-loop biomass with coal, other biomass, or coal and other 

biomass, a qualified facility must be originally placed in service and modified to co-fire the 

closed-loop biomass at any time before January 1, 2014. 

A qualified facility includes a new power generation unit placed in service after October 

3, 2008, at an existing closed-loop biomass facility, but only to the extent of the increased 

amount of electricity produced at the existing facility by reason of such new unit. 

Open-loop biomass (including agricultural livestock waste nutrients) facility

An open-loop biomass facility is a facility that uses open-loop biomass to produce 

electricity. For purposes of the credit, open-loop biomass is defined as (1) any agricultural 

livestock waste nutrients or (2) any solid, nonhazardous, cellulosic waste material or any lignin 

material that is segregated from other waste materials and which is derived from: 

 forest-related resources, including mill and harvesting residues, precommercial 

thinnings, slash, and brush; 

 solid wood waste materials, including waste pallets, crates, dunnage, manufacturing 

and construction wood wastes, and landscape or right-of-way tree trimmings; or 

 agricultural sources, including orchard tree crops, vineyard, grain, legumes, sugar, 

and other crop by-products or residues. 

Agricultural livestock waste nutrients are defined as agricultural livestock manure and 

litter, including bedding material for the disposition of manure. Wood waste materials do not 

qualify as open-loop biomass to the extent they are pressure treated, chemically treated, or 

painted. In addition, municipal solid waste, gas derived from the biodegradation of solid waste, 

and paper that is commonly recycled do not qualify as open-loop biomass. Open-loop biomass 

does not include closed-loop biomass or any biomass burned in conjunction with fossil fuel (cofiring) beyond such fossil fuel required for start up and flame stabilization. 

In the case of an open-loop biomass facility that uses agricultural livestock waste 

nutrients, a qualified facility is one that was originally placed in service after October 22, 2004, 

and before January 1, 2014, and has a nameplate capacity rating which is not less than 150 

kilowatts. In the case of any other open-loop biomass facility, a qualified facility is one that was 

originally placed in service before January 1, 2014. A qualified facility includes a new power 
33 

generation unit placed in service after October 3, 2008, at an existing open-loop biomass facility, 

but only to the extent of the increased amount of electricity produced at the existing facility by 

reason of such new unit. 

Geothermal facility

A geothermal facility is a facility that uses geothermal energy to produce electricity. 

Geothermal energy is energy derived from a geothermal deposit that is a geothermal reservoir 

consisting of natural heat that is stored in rocks or in an aqueous liquid or vapor (whether or not 

under pressure). To be a qualified facility, a geothermal facility must be placed in service after 

October 22, 2004, and before January 1, 2014. 

Solar facility

A solar facility is a facility that uses solar energy to produce electricity. To be a qualified 

facility, a solar facility must be placed in service after October 22, 2004, and before January 1, 

2006. 

Small irrigation facility

A small irrigation power facility is a facility that generates electric power through an 

irrigation system canal or ditch without any dam or impoundment of water. The installed 

capacity of a qualified facility must be at least 150 kilowatts but less than five megawatts. To be 

a qualified facility, a small irrigation facility must be originally placed in service after 

October 22, 2004, and before October 3, 2008. Marine and hydrokinetic renewable energy 

facilities, described below, subsume small irrigation power facilities after October 2, 2008. 

Landfill gas facility

A landfill gas facility is a facility that uses landfill gas to produce electricity. Landfill gas 

is defined as methane gas derived from the biodegradation of municipal solid waste. To be a 

qualified facility, a landfill gas facility must be placed in service after October 22, 2004, and 

before January 1, 2014. 

Trash combustion facility

Trash combustion facilities are facilities that use municipal solid waste (garbage) to 

produce steam to drive a turbine for the production of electricity. To be a qualified facility, a 

trash combustion facility must be placed in service after October 22, 2004, and before January 1, 

2014. A qualified trash combustion facility includes a new unit, placed in service after 

October 22, 2004, that increases electricity production capacity at an existing trash combustion 

facility. A new unit generally would include a new burner/boiler and turbine. The new unit may 

share certain common equipment, such as trash handling equipment, with other pre-existing units 

at the same facility. Electricity produced at a new unit of an existing facility qualifies for the 

production credit only to the extent of the increased amount of electricity produced at the entire 

facility. 
34 

Hydropower facility

A qualifying hydropower facility is (1) a facility that produced hydroelectric power (a 

hydroelectric dam) prior to August 8, 2005, at which efficiency improvements or additions to 

capacity have been made after such date and before January 1, 2011, that enable the taxpayer to 

produce incremental hydropower or (2) a facility placed in service before August 8, 2005, that 

did not produce hydroelectric power (a nonhydroelectric dam) on such date, and to which 

turbines or other electricity generating equipment have been added after such date and before 

January 1, 2014. 

At an existing hydroelectric facility, the taxpayer may claim credit only for the 

production of incremental hydroelectric power. Incremental hydroelectric power for any taxable 

year is equal to the percentage of average annual hydroelectric power produced at the facility 

attributable to the efficiency improvement or additions of capacity determined by using the same 

water flow information used to determine an historic average annual hydroelectric power 

production baseline for that facility. The Federal Energy Regulatory Commission will certify the 

baseline power production of the facility and the percentage increase due to the efficiency and 

capacity improvements. 

Nonhydroelectric dams converted to produce electricity must be licensed by the Federal 

Energy Regulatory Commission and meet all other applicable environmental, licensing, and 

regulatory requirements. 

For a nonhydroelectric dam converted to produce electric power before January 1, 2009, 

there must not be any enlargement of the diversion structure, construction or enlargement of a 

bypass channel, or the impoundment or any withholding of additional water from the natural 

stream channel. 

For a nonhydroelectric dam converted to produce electric power after December 31, 

2008, the nonhydroelectric dam must (1) have been placed in service before October 3, 2008, (2) 

have been operated for flood control, navigation, or water supply purposes and (3) not have 

produce hydroelectric power on October 3, 2008. In addition, the hydroelectric project must be 

operated so that the water surface elevation at any given location and time that would have 

occurred in the absence of the hydroelectric project is maintained, subject to any license 

requirements imposed under applicable law that change the water surface elevation for the 

purpose of improving environmental quality of the affected waterway. The Secretary, in 

consultation with the Federal Energy Regulatory Commission, shall certify if a hydroelectric 

project licensed at a nonhydroelectric dam meets this criteria. 

Marine and hydrokinetic renewable energy facility

A qualified marine and hydrokinetic renewable energy facility is any facility that 

produces electric power from marine and hydrokinetic renewable energy, has a nameplate 

capacity rating of at least 150 kilowatts, and is placed in service after October 2, 2008, and 

before January 1, 2014. Marine and hydrokinetic renewable energy is defined as energy derived 

from (1) waves, tides, and currents in oceans, estuaries, and tidal areas; (2) free flowing water in 

rivers, lakes, and streams; (3) free flowing water in an irrigation system, canal, or other man-
35 

made channel, including projects that utilize nonmechanical structures to accelerate the flow of 

water for electric power production purposes; or (4) differentials in ocean temperature (ocean 

thermal energy conversion). The term does not include energy derived from any source that uses 

a dam, diversionary structure (except for irrigation systems, canals, and other man-made 

channels), or impoundment for electric power production. 

Taxation of cooperatives and their patrons

For Federal income tax purposes, a cooperative generally computes its income as if it 

were a taxable corporation, with one exception: the cooperative may exclude from its taxable 

income distributions of patronage dividends. Generally, a cooperative that is subject to the 

cooperative tax rules of subchapter T of the Code18 is permitted a deduction for patronage 

dividends paid only to the extent of net income that is derived from transactions with patrons 

who are members of the cooperative.19 The availability of such deductions from taxable income 

has the effect of allowing the cooperative to be treated like a conduit with respect to profits 

derived from transactions with patrons who are members of the cooperative. 

Eligible cooperatives may elect to pass any portion of the credit through to their patrons. 

An eligible cooperative is defined as a cooperative organization that is owned more than 50 

percent by agricultural producers or entities owned by agricultural producers. The credit may be 

apportioned among patrons eligible to share in patronage dividends on the basis of the quantity 

or value of business done with or for such patrons for the taxable year. The election must be 

made on a timely filed return for the taxable year and, once made, is irrevocable for such taxable 

year. 

4. Energy credit (sec. 48) 

In general

A nonrefundable, 10-percent business energy credit20 is allowed for the cost of new 

property that is equipment that either (1) uses solar energy to generate electricity, to heat or cool 

a structure, or to provide solar process heat or (2) is used to produce, distribute, or use energy 

derived from a geothermal deposit, but only, in the case of electricity generated by geothermal 

power, up to the electric transmission stage. Property used to generate energy for the purposes of 

heating a swimming pool is not eligible solar energy property. 

The energy credit is a component of the general business credit.21 An unused general 

business credit generally may be carried back one year and carried forward 20 years.22 The 

 18 Secs. 1381-1383. 

19 Sec. 1382. 

20 Sec. 48. 

21 Sec. 38(b)(1). 

22 Sec. 39. 
36 

taxpayer’s basis in the property is reduced by one-half of the amount of the credit claimed. For 

projects whose construction time is expected to equal or exceed two years, the credit may be 

claimed as progress expenditures are made on the project, rather than during the year the 

property is placed in service. The credit is allowed against the alternative minimum tax for 

credits determined in taxable years beginning after October 3, 2008. 

Special rules for solar energy property

The credit for solar energy property is increased to 30 percent in the case of periods prior 

to January 1, 2017. Additionally, equipment that uses fiber-optic distributed sunlight to 

illuminate the inside of a structure is solar energy property eligible for the 30-percent credit. 

Fuel cells and microturbines

The energy credit applies to qualified fuel cell power plants, but only for periods prior to 

January 1, 2017. The credit rate is 30 percent. 

A qualified fuel cell power plant is an integrated system composed of a fuel cell stack 

assembly and associated balance of plant components that (1) converts a fuel into electricity 

using electrochemical means, and (2) has an electricity-only generation efficiency of greater than 

30 percent and a capacity of at least one-half kilowatt. The credit may not exceed $1,500 for 

each 0.5 kilowatt of capacity. 

The energy credit applies to qualifying stationary microturbine power plants for periods 

prior to January 1, 2017. The credit is limited to the lesser of 10 percent of the basis of the 

property or $200 for each kilowatt of capacity. 

A qualified stationary microturbine power plant is an integrated system comprised of a 

gas turbine engine, a combustor, a recuperator or regenerator, a generator or alternator, and 

associated balance of plant components that converts a fuel into electricity and thermal energy. 

Such system also includes all secondary components located between the existing infrastructure 

for fuel delivery and the existing infrastructure for power distribution, including equipment and 

controls for meeting relevant power standards, such as voltage, frequency and power factors. 

Such system must have an electricity-only generation efficiency of not less than 26 percent at 

International Standard Organization conditions and a capacity of less than 2,000 kilowatts. 

Geothermal heat pump property

The energy credit applies to qualified geothermal heat pump property placed in service 

prior to January 1, 2017. The credit rate is 10 percent. Qualified geothermal heat pump property 

is equipment that uses the ground or ground water as a thermal energy source to heat a structure 

or as a thermal energy sink to cool a structure. 

Small wind property

The energy credit applies to qualified small wind energy property placed in service prior 

to January 1, 2017. The credit rate is 30 percent. Qualified small wind energy property is 
37 

property that uses a qualified wind turbine to generate electricity. A qualifying wind turbine 

means a wind turbine of 100 kilowatts of rated capacity or less. 

Combined heat and power property

The energy credit applies to combined heat and power (“CHP”) property placed in 

service prior to January 1, 2017. The credit rate is 10 percent. 

CHP property is property: (1) that uses the same energy source for the simultaneous or 

sequential generation of electrical power, mechanical shaft power, or both, in combination with 

the generation of steam or other forms of useful thermal energy (including heating and cooling 

applications); (2) that has an electrical capacity of not more than 50 megawatts or a mechanical 

energy capacity of not more than 67,000 horsepower or an equivalent combination of electrical 

and mechanical energy capacities; (3) that produces at least 20 percent of its total useful energy 

in the form of thermal energy that is not used to produce electrical or mechanical power, and 

produces at least 20 percent of its total useful energy in the form of electrical or mechanical 

power (or a combination thereof); and (4) the energy efficiency percentage of which exceeds 60 

percent. CHP property does not include property used to transport the energy source to the 

generating facility or to distribute energy produced by the facility. 

The otherwise allowable credit with respect to CHP property is reduced to the extent the 

property has an electrical capacity or mechanical capacity in excess of any applicable limits. 

Property in excess of the applicable limit (15 megawatts or a mechanical energy capacity of 

more than 20,000 horsepower or an equivalent combination of electrical and mechanical energy 

capacities) is permitted to claim a fraction of the otherwise allowable credit. The fraction is equal 

to the applicable limit divided by the capacity of the property. For example, a 45 megawatt 

property would be eligible to claim 15/45ths, or one third, of the otherwise allowable credit. 

Again, no credit is allowed if the property exceeds the 50 megawatt or 67,000 horsepower 

limitations described above. 

Additionally, systems whose fuel source is at least 90 percent open-loop biomass and that 

would qualify for the credit but for the failure to meet the efficiency standard are eligible for a 

credit that is reduced in proportion to the degree to which the system fails to meet the efficiency 

standard. For example, a system that would otherwise be required to meet the 60-percent 

efficiency standard, but which only achieves 30-percent efficiency, would be permitted a credit 

equal to one-half of the otherwise allowable credit (i.e., a 5-percent credit). 

Election of energy credit in lieu of sec. 45 production tax credit

A taxpayer may make an irrevocable election to have certain qualified facilities placed in 

service in 2009 through 2013 (2012 for wind facilities) be treated as energy property eligible for 

a 30 percent investment credit under section 48. For this purpose, qualified facilities are 

facilities otherwise eligible for the section 4523 production tax credit (other than refined coal, 

 23 See section II.A.3 of this pamphlet for a discussion of sec. 45 qualified facilities eligible for 

this provision. 
38 

Indian coal, and solar facilities) with respect to which no credit under section 45 has been 

allowed. A taxpayer electing to treat a facility as energy property may not claim the production 

credit under section 45. 

The eligible basis for the investment credit for taxpayers making this election is the basis 

of the depreciable (or amortizable) property that would comprise a section 45 credit-eligible 

facility. For example, in the case of a wind facility, only property eligible for five- year 

depreciation under section 168(e)(3)(b)(vi) is treated as credit-eligible energy property under the 

election. 

5. Clean renewable energy bonds and new clean renewable energy bonds 

(secs. 54 and 54C) 

Both Clean Renewable Energy Bonds (“CREBs”) and New Clean Renewable Energy 

Bonds (“New CREBs”) are types of tax credit bonds that can be used to finance certain facilities 

that produce electricity from certain renewable resources. CREBs are subject to a national 

volume cap of $1.2 billion24 and must be issued by December 31, 2009.25 A taxpayer holding a 

CREB on a credit allowance date is entitled to a credit against its Federal income taxes. As 

discussed in more detail below, the annual credit with respect to a CREB is equal to the amount 

that the Treasury Secretary determines would allow the CREB to be issued at par and without 

interest.26

New CREBs are subject to a national volume cap of $2.4 billion.27 A taxpayer holding a 

New CREB on a credit allowance date is entitled to a credit against its Federal income taxes. As 

discussed in more detail below, the annual credit with respect to a New CREB is equal to 70 

percent of the credit that the Treasury Secretary determines would allow the New CREB to be 

issued at par and without interest.28 Because the credit is only 70 percent of the credit that would 

permit the New CREB to be issued at par, it is assumed that the New CREB will be interest 

bearing and/or issued at a discount. The tax credit to a holder of a New CREB is treated as 

interest that is includible in the holder’s gross income, and any interest paid on a New CREB is 

taxable.29

 24 Sec. 54(f). 

25 Sec. 54D(a). 

26 Sec. 54(b). 

27 Sec. 54C(c); see also Notice 2009-33, 2009-17 I.R.B. (April 6, 2009) (soliciting applications 

for the present total national bond volume limitation for New CREBs and providing guidance on (1) 

eligibility requirements; (2) application requirements; (3) the method for allocating volume cap; and (4) 

certain other aspects of the rules). 

28 Sec. 54C(b). 

29 Sec. 54A(f). 
39 

CREBs

CREBs are defined as any bond issued by a “qualified issuer” if, in addition to the 

requirements discussed below, 95 percent or more of the proceeds from the issuance of such 

bonds are used to finance capital expenditures incurred by “qualified borrowers” for facilities 

that qualify for the tax credit under section 45 (other than Indian coal production facilities), 

without regard to the placed-in-service date requirements of that section.30 The term “qualified 

issuer” includes (1) governmental bodies (including Indian tribal governments); (2) mutual or 

cooperative electric companies (described in section 501(c)(12) or section 1381(a)(2)(C), or a 

not-for-profit electric utility which has received a loan or guarantee under the Rural 

Electrification Act); and (3) clean energy bond lenders.31 The term “qualified borrower” 

includes a governmental body (including an Indian tribal government) and a mutual or 

cooperative electric company.32

Projects that may be financed with CREBs include any facility owned by a qualified 

borrower that is functionally related and subordinate (as determined under Treas. Reg. sec. 

1.103-8(a)(3)) to any qualified facility described in sections 45(d)(1) through (d)(9) (determined 

without regard to any placed in service date) and owned by such qualified borrower.33 

The credit rate on a CREB is determined by the Secretary and is to be a rate that permits 

issuance of CREBs without discount and interest cost to the qualified issuer. 34 The credit 

accrues quarterly and is includible in gross income (as if it were an interest payment on the 

bond), and can be claimed against regular income tax liability and alternative minimum tax 

liability. 

CREBs are subject to a maximum maturity limitation.35 The maximum maturity is the 

term which the Secretary estimates will result in the present value of the obligation to repay the 

principal on a CREBs being equal to 50 percent of the face amount of such bond. In addition, the 

Code requires level amortization of CREBs during the period such bonds are outstanding. 

CREBs also are subject to the arbitrage requirements of section 148 that apply to 

traditional tax-exempt bonds. Principles under section 148 and the regulations thereunder apply 

 30 Sec. 54(d). 

31 Sec. 54(j)(4). 

32 Sec. 54(j)(5). 

33 Internal Revenue Service, Notice 2006-7, Clean Renewable Energy Bonds, 2006-1 C.B. 559 

(March 6, 2006). 

34 Sec. 54(b). 

35 Sec. 54(e). 
40 

for purposes of determining the yield restriction and arbitrage rebate requirements applicable to 

CREBs.36 

To qualify as CREBs, the qualified issuer must reasonably expect to and actually spend 

95 percent or more of the proceeds of from the issuance of such bonds on qualified projects 

within the five-year period that begins on the date of issuance.37 To the extent less than 95 

percent of the proceeds are used to finance qualified projects during the five-year spending 

period, bonds will continue to qualify as CREBs if unspent proceeds are used within 90 days 

from the end of such five-year period to redeem any “nonqualified bonds.” The five-year 

spending period may be extended by the Secretary upon the qualified issuer’s request 

demonstrating that the failure to satisfy the five-year requirement is due to reasonable cause and 

the projects will continue to proceed with due diligence. 

Allocations of CREB authority were made in 2006 and 2008. The table below reflects 

those allocations. 

 36 Sec. 54(i). 

37 Sec. 54(h). 
41 

Table 1.−Clean Renewable Energy Bond Allocations38 (2006 and 2008)

Type of Borrower Type of Project Number of Projects 

Governmental Solar 539 

Wind 187 

Landfill gas 64 

Open loop biomass 1 

Closed loop biomass 3 

Trash combustion 3 

Hydropower 13 

Cooperatives Solar 34 

Wind 27 

Landfill gas 17 

Open loop biomass 13 

Hydropower 12 

Refined coal 1 

 38 This table is based on Announcement 2006-181 (November 20, 2006) and Announcement 

2008-16 (February 8, 2008). Pursuant to the Energy Tax Incentives Act of 2005 (Pub. L. No. 109-58), 

the Treasury Department allocated $800 million of CREBs based on a “smallest-to-largest” project 

amount methodology -- beginning with the project requesting the smallest dollar amount and proceeding 

thereafter to projects for successively larger dollar amounts until the total national volume cap of $800 

million was allocated among 610 projects (some of the allocations were subsequently relinquished). The 

allocations for governmental borrowers ranged from $23,000 to approximately $3.2 million. The 

allocations for cooperatives ranged from $120,548 to $31 million. The Tax Relief and Health Care Act of 

2006 (Pub. L. No. 109-432) increased the available national allocation from $800 million to $1.2 billion. 

In 2008, the Treasury Department made a second round of allocations of approximately $406 million 

distributed among another 312 projects. For the second round, the allocations for governmental 

borrowers ranged from $15,000 to $2.95 million, and $300,000 to $30 million for cooperative borrowers. 
42 

New CREBs

Section 107 of the Energy Improvement and Extension Act of 2008 (Division B of Pub. 

L. No. 110-343) added a new section 54C of the Code for new clean renewable energy bonds 

(“New CREBs”). New CREBs may be issued by “qualified issuers” to finance “qualified 

renewable energy facilities.” Qualified renewable energy facilities are facilities that: (1) qualify 

for the tax credit under section 45 (other than Indian coal and refined coal production facilities), 

without regard to the placed-in-service date requirements of that section; and (2) are owned by a 

public power provider, governmental body, or cooperative electric company. 

The term “qualified issuer” includes: (1) public power providers; (2) a governmental 

body; (3) cooperative electric companies; (4) a not-for-profit electric utility that has received a 

loan or guarantee under the Rural Electrification Act; and (5) clean renewable energy bond 

lenders. The term “public power provider” means a State utility with a service obligation, as 

such terms are defined in section 217 of the Federal Power Act (as in effect on the date of the 

enactment of this paragraph). A “governmental body” means any State or Indian tribal 

government, or any political subdivision thereof. The term “cooperative electric company” 

means a mutual or cooperative electric company (described in section 501(c)(12) or section 

1381(a)(2)(C)). A clean renewable energy bond lender means a cooperative that is owned by, or 

has outstanding loans to, 100 or more cooperative electric companies and is in existence on 

February 1, 2002 (including any affiliated entity which is controlled by such lender). 

There is a national limitation for New CREBs of $2.4 billion.39 No more than one third 

of the national limit may be allocated to projects of public power providers, governmental 

bodies, or cooperative electric companies. Allocations to governmental bodies and cooperative 

electric companies may be made in the manner the Secretary determines appropriate. 

Allocations to projects of public power providers shall be made, to the extent practicable, in such 

manner that the amount allocated to each such project bears the same ratio to the cost of such 

project as the maximum allocation limitation to projects of public power providers bears to the 

cost of all such projects. 

New CREBs are a type of qualified tax credit bond for purposes of section 54A of the 

Code. As such, 100 percent of the available project proceeds of New CREBs must be used 

within the three-year period that begins on the date of issuance.40 Available project proceeds are 

proceeds from the sale of the bond issue less issuance costs (not to exceed two percent) and any 

investment earnings on such sale proceeds. To the extent less than 100 percent of the available 

project proceeds are used to finance qualified projects during the three-year spending period, 

bonds will continue to qualify as New CREBs if unspent proceeds are used within 90 days from 

the end of such three-year period to redeem bonds. The three-year spending period may be 

extended by the Secretary upon the qualified issuer’s request demonstrating that the failure to 

 39 Sec. 54C(c); see also Notice 2009-33. Section 1111 of Title I of Division B of the American 

Recovery and Reinvestment Act of 2009 (Pub. L. No. 111-5) increased the national bond volume 

limitation for New CREBs by $1.6 billion, from $800 million to $2.4 billion. 

40 Sec. 54A(d)(2). 
43 

satisfy the three-year requirement is due to reasonable cause and the projects will continue to 

proceed with due diligence. 

New CREBs generally are subject to the arbitrage requirements of section 148.41 

However, available project proceeds invested during the three-year spending period are not 

subject to the arbitrage restrictions (i.e., yield restriction and rebate requirements). In addition, 

amounts invested in a reserve fund are not subject to the arbitrage restrictions to the extent: (1) 

such fund is funded at a rate not more rapid than equal annual installments; (2) such fund is 

funded in a manner reasonably expected to result in an amount not greater than an amount 

necessary to repay the issue; and (3) the yield on such fund is not greater than the average annual 

interest rate of tax-exempt obligations having a term of 10 years or more that are issued during 

the month the New CREBs are issued. 

As with other tax credit bonds, a taxpayer holding a New CREB on a credit allowance 

date is entitled to a tax credit; the credit rate on New CREBs is set by the Secretary at a rate that 

is 70 percent of the rate that would permit issuance of such bonds without discount and interest 

cost to the issuer.42 The Secretary determines credit rates for tax credit bonds based on general 

assumptions about credit quality of the class of potential eligible issuers and such other factors as 

the Secretary deems appropriate. The Secretary may determine credit rates based on general 

credit market yield indexes and credit ratings.43 

The amount of the tax credit is determined by multiplying the bond’s credit rate by the 

face amount of the holder’s bond. The credit accrues quarterly, is includible in gross income (as 

if it were an interest payment on the bond), and can be claimed against regular income tax 

liability and alternative minimum tax liability. Unused credits may be carried forward to 

succeeding taxable years. In addition, credits may be separated from the ownership of the 

underlying bond similar to how interest coupons can be stripped for interest-bearing bonds. 

An issuer of New CREBs is treated as meeting the “prohibition on financial conflicts of 

interest” requirement in section 54A(d)(6) if it certifies that it satisfies (1) applicable State and 

local law requirements governing conflicts of interest and (2) any additional conflict of interest 

rules prescribed by the Secretary with respect to any Federal, State, or local government official 

directly involved with the issuance of New CREBs. 

 41 Sec. 54A(d)(4). 

42 Given the differences in credit quality and other characteristics of individual issuers, the 

Secretary cannot set credit rates in a manner that will allow each issuer to issue tax credit bonds at par. 

43 See Internal Revenue Service, Notice 2009-15, Credit Rates on Tax Credit Bonds, 2009-6 

I.R.B. 1 (January 22, 2009). 
44 

6. Five-year cost recovery of certain energy property (sec. 168) 

In general

A taxpayer is allowed to recover, through annual depreciation deductions, the cost of 

certain property used in a trade or business or for the production of income. The amount of the 

depreciation deduction allowed with respect to tangible property for a taxable year is determined 

under the modified accelerated cost recovery system (“MACRS”). Under MACRS, different 

types of property are generally assigned applicable recovery periods and depreciation methods. 

The recovery periods applicable to most tangible personal property (generally tangible property 

other than residential rental property and nonresidential real property) range from three to 25 

years. The depreciation methods generally applicable to tangible personal property are the 200-

percent and 150-percent declining balance methods, switching to the straight-line method for the 

taxable year in which the depreciation deduction would be maximized.44 In general, the recovery 

periods applicable to real property are 39 years for non-residential real property and 27.5 years 

for residential rental property. The depreciation method for real property is the straight-line 

method. 

Under MACRS, the full basis of depreciable property is recovered by the taxpayer over 

the applicable recovery period; there is no need to estimate salvage value. Furthermore, under 

MACRS, the applicable recovery period need not (and typically does not) correspond to the 

actual economic life of the asset subject to depreciation. In general, however, MACRS generally 

provides for longer recovery periods for longer lived assets. 

Certain energy property

The Code provides a five-year statutory recovery period for certain energy property,45

including (i) equipment which uses solar and wind energy to generate electricity, to heat or cool 

(or provide hot water for use in) a structure, or to provide solar process heat, except property 

used to generate energy for the purposes of heating a swimming pool; (ii) equipment which uses 

solar energy to illuminate the inside of a structure using fiber-optic distributed sunlight;46 (iii) 

equipment used to produce, distribute, or use energy derived from a geothermal deposit,47 but 

only, in the case of electricity generated by geothermal power, up to (but not including) the 

 44 For certain property, including tangible property used predominantly outside the United States, 

tax-exempt use property, tax-exempt bond-financed property, and certain other property, the MACRS 

“alternative depreciation system” of section 168(g) applies, generally increasing recovery periods and 

requiring straight-line depreciation. 

45 Sec. 168(e)(3)(B)(vi)(I). 

46 Only with respect to periods ending before January 1, 2017. 

47 Geothermal deposit is defined by reference to section 613(e)(2) as a geothermal reservoir 

consisting of natural heat which is stored in rocks or in an aqueous liquid or vapor (whether or not under 

pressure). 
45 

electrical transmission stage; and (iv) qualified fuel cell property48 or qualified microturbine 

property.49

Biomass property

Certain biomass property has a statutory recovery period of five years.50 For purposes of 

this provision, biomass property includes (i) a boiler, the primary fuel for which will be an 

alternate substance; (ii) a burner (including necessary on-site equipment to bring the alternate 

substance to the burner) for a combustor other than a boiler if the primary fuel for such burner 

will be an alternate substance; and (iii) equipment for converting an alternate substance into a 

qualified fuel.51 Such property also includes pollution control equipment52 required (by Federal, 

State, or local regulations) to be installed on or in connection with the above mentioned property 

and equipment used for the unloading, transfer, storage, reclaiming from storage, and preparation 

(including, but not limited to, washing, crushing, drying, and weighing) at the point of use of an 

alternate substance for use in equipment described above.53

For purposes of this provision, the term “alternate substance” means any substance other 

than oil and natural gas, and any product of oil and natural gas. 

The property must also be a “qualifying small power production facility.” For purposes 

of this provision, the term “qualifying small power production facility” means a “small power 

production facility” that the Federal Power Commission determines, by rule, meets such 

requirements (including requirements respecting fuel use, fuel efficiency, and reliability) as the 

 48 Qualified fuel cell property is defined as a fuel cell power plant which has a nameplate 

capacity of at least 0.5 kilowatt of electricity using an electrochemical process, and has an electricity-only 

generation efficiency greater than 30 percent. 

49 Qualified microturbine property is defined as a stationary microturbine power plant which has 

a nameplate capacity of less than 2,000 kilowatts, and has an electricity-only generation efficiency of not 

less than 26 percent at International Standard Organization conditions. 

50 Sec. 168(e)(3)(B)(vi)(II). 

51 This definition is included by reference to section 48(l)(15) as in effect on the day before the 

date of the enactment (Nov. 5, 1990) of the Revenue Reconciliation Act of 1990. 

The term “qualified fuel” means any synthetic solid fuel, and alcohol for fuel purposes if the 

primary source of energy for the facility producing the alcohol is not oil or natural gas or a product of oil 

or natural gas. 

52 The term “pollution control equipment” does not include any equipment which is installed on 

or in connection with property which, as of October 1, 1978, was using coal (including lignite), and was 

required to be installed by Federal, State, or local regulations in effect on such date. 

53 This equipment also includes equipment used for the storage of fuel derived from garbage at 

the site at which such fuel was produced from garbage. 
46 

Commission may, by rule, prescribe, and which is owned by a person not primarily engaged in 

the generation or sale of electric power (other than electric power solely from cogeneration 

facilities or small power production facilities).54 The term “small power production facility” 

means a facility which (i) produces electric energy solely by the use, as a primary energy source, 

of biomass, waste, renewable resources, geothermal resources, or any combination thereof; and 

(ii) has a power production capacity which, together with any other facilities located at the same 

site (as determined by the Federal Power Commission), is not greater than 80 megawatts.55

7. Special allowance for cellulosic biofuel plant property (sec. 168(l)) 

The Code provides an additional first-year depreciation deduction equal to 50 percent of 

the adjusted basis of qualified cellulosic biofuel plant property. In order to qualify, the property 

generally must be placed in service before January 1, 2013.

Qualified cellulosic biofuel plant property means property used in the U.S. solely to 

produce cellulosic biofuel. For this purpose, cellulosic biofuel means any liquid fuel which is 

produced by any lignocellulosic or hemicellulosic matter that is available on a renewable or 

recurring basis. For example, lignocellulosic or hemicellulosic matter that is available on a 

renewable or recurring basis includes bagasse (from sugar cane), corn stalks, and switchgrass. 

The additional first-year depreciation deduction is allowed for both regular tax and 

alternative minimum tax purposes for the taxable year in which the property is placed in service. 

The additional first-year depreciation deduction is subject to the general rules regarding whether 

an item is deductible under section 162 or subject to capitalization under section 263 or section 

263A. The basis of the property and the depreciation allowances in the year of purchase and 

later years are appropriately adjusted to reflect the additional first-year depreciation deduction. 

In addition, the provision provides that there is no adjustment to the allowable amount of 

depreciation for purposes of computing a taxpayer’s alternative minimum taxable income with 

respect to property to which the provision applies. A taxpayer is allowed to elect out of the 

additional first-year depreciation for any class of property for any taxable year. 

To qualify for the additional first-year depreciation deduction, the original use of the 

property must commence with the taxpayer after December 20, 2006. The property must be 

acquired by purchase (as defined under section 179(d)) by the taxpayer after December 20, 2006 

and be placed in service before January 1, 2013. Property does not qualify if a binding written 

contract for the acquisition of such property was in effect on or before December 20, 2006. 

Property that is manufactured, constructed, or produced by the taxpayer for use by the 

taxpayer qualifies if the taxpayer begins the manufacture, construction, or production of the 

property after December 20, 2006, and the property is placed in service before January 1, 2013 

 54 This definition is included by reference to the Federal Power Act (16 U.S.C. 796(17)(C)), as in 

effect on September 1, 1986. 

55 This definition is included by reference to the Federal Power Act (16 U.S.C. 796(17)(A)), as in 

effect on September 1, 1986. 
47 

(and all other requirements are met). Property that is manufactured, constructed, or produced for 

the taxpayer by another person under a contract that is entered into prior to the manufacture, 

construction, or production of the property is considered to be manufactured, constructed, or 

produced by the taxpayer. 

Qualified cellulosic biofuel plant property does not include property to which section 

168(k) (providing “bonus depreciation”) applies; alternative depreciation property as defined 

under section 168(k)(2)(D)(i); tax-exempt bond financed property; or property for which the 

taxpayer has elected not to claim the special allowance under section 168(l). Recapture rules 

apply if the property ceases to be qualified cellulosic biofuel plant property. 
48 

B. Provisions Relating to Energy Conservation 

1. Credit for nonbusiness energy property (sec. 25C) 

In general

Section 25C provides a 30-percent credit for the purchase of qualified energy efficiency 

improvements to the envelope of existing homes. Additionally, section 25C provides a 30 

percent credit for the purchase of (1) qualified natural gas, propane, or oil furnace or hot water 

boilers, (2) qualified energy efficient property, and (3) advanced main air circulating fans. 

The credit applies to expenditures made after December 31, 2008 for property placed in 

service after December 31, 2008, and prior to January 1, 2011.56 The aggregate amount of the 

credit allowed for a taxpayer for taxable years beginning in 2009 and 2010 is $1,500. 

Building envelope improvements

A qualified energy efficiency improvement is any energy efficiency building envelope 

component (1) that meets or exceeds the prescriptive criteria for such a component established 

by the 2000 International Energy Conservation Code57 as supplemented and as in effect on 

August 8, 2005 (or, in the case of metal roofs with appropriate pigmented coatings, meets the 

Energy Star program requirements); (2) that is installed in or on a dwelling located in the United 

States and owned and used by the taxpayer as the taxpayer’s principal residence; (3) the original 

use of which commences with the taxpayer; and (4) that reasonably can be expected to remain in 

use for at least five years. The credit is nonrefundable. 

Building envelope components are: (1) insulation materials or systems which are 

specifically and primarily designed to reduce the heat loss or gain for a dwelling and which meet 

the prescriptive criteria for such material or system established by the 2009 International Energy 

Conservation Code, as such Code (including supplements) is in effect on the date of the 

enactment of the American Recovery and Reinvestment Tax Act of 2009 (February 17, 2009); 

(2) exterior windows (including skylights) and doors provided such component has a U-factor 

and a seasonal heat gain coefficient (“SHGC”) of 0.3 or less; and (3) metal or asphalt roofs with 

appropriate pigmented coatings or cooling granules that are specifically and primarily designed 

to reduce the heat gain for a dwelling. 

 56 With the exception of biomass fuel property, property placed in service after December 31, 

2008 and prior to February 17, 2009 qualifies for the new 30 percent credit rate (and $1,500 aggregate 

cap) if it met the efficiency standards of prior law for property placed in service during 2009. Biomass 

fuel property placed in service at any point in 2009 is governed by the new efficiency standard. 

57 This reference to the 2000 International Energy Conservation Code is superseded by the 

additional requirements described in the paragraph below regarding building envelope components. 
49 

Other eligible property

Qualified natural gas, propane, or oil furnace or hot water boilers

A qualified natural gas, propane, or oil hot water boiler is a natural gas, propane, or oil 

hot water boiler with an annual fuel utilization efficiency rate of at least 90. A qualified natural 

gas or propane furnace is a natural gas or propane furnace with an annual fuel utilization 

efficiency rate of at least 95. A qualified oil furnace is an oil furnace with an annual fuel 

utilization efficiency rate of at least 90. 

Qualified energy-efficient property

Qualified energy-efficient property is: (1) an electric heat pump water heater which yields 

an energy factor of at least 2.0 in the standard Department of Energy test procedure, (2) an 

electric heat pump which achieves the highest efficiency tier of Consortium for Energy 

Efficiency, as in effect on January 1, 2009,58 (3) a central air conditioner with energy efficiency 

of at least the highest efficiency tier established by the Consortium for Energy Efficiency as in 

effect on Jan. 1, 200959, (4) a natural gas, propane, or oil water heater which has an energy factor 

of at least 0.82 or thermal efficiency of at least 90 percent, and (5) biomass fuel property. 

 Biomass fuel property is a stove that burns biomass fuel to heat a dwelling unit located 

in the United States and used as a principal residence by the taxpayer, or to heat water for such 

dwelling unit, and that has a thermal efficiency rating of at least 75 percent as measured using a 

lower heating value. Biomass fuel is any plant-derived fuel available on a renewable or 

recurring basis, including agricultural crops and trees, wood and wood waste and residues 

(including wood pellets), plants (including aquatic plants, grasses, residues, and fibers). 

Advanced main air circulating fan

An advanced main air circulating fan is a fan used in a natural gas, propane, or oil 

furnace originally placed in service by the taxpayer during the taxable year, and which has an 

annual electricity use of no more than two percent of the total annual energy use of the furnace 

(as determined in the standard Department of Energy test procedures). 

 58 These standards are a seasonal energy efficiency ratio (“SEER”) greater than or equal to 15, an 

energy efficiency ratio (“EER”) greater than or equal to 12.5, and heating seasonal performance factor 

(“HSPF “) greater than or equal to 8.5 for split heat pumps, and SEER greater than or equal to 14, EER 

greater than or equal to 12, and HSPF greater than or equal to 8.0 for packaged heat pumps. 

59 These standards are a SEER greater than or equal to 16 and EER greater than or equal to 13 for 

split systems, and SEER greater than or equal to 14 and EER greater than or equal to 12 for packaged 

systems. 
50 

Additional rules

The taxpayer’s basis in the property is reduced by the amount of the credit. Special 

proration rules apply in the case of jointly owned property, condominiums, and tenantstockholders in cooperative housing corporations. If less than 80 percent of the property is used 

for nonbusiness purposes, only that portion of expenditures that is used for nonbusiness purposes 

is taken into account. 

2. Credit for residential energy efficient property (sec. 25D) 

In general

Section 25D provides a personal tax credit for the purchase of qualified solar electric 

property and qualified solar water heating property that is used exclusively for purposes other 

than heating swimming pools and hot tubs. The credit is equal to 30 percent of qualifying 

expenditures. 

Section 25D also provides a 30 percent credit for the purchase of qualified geothermal 

heat pump property, qualified small wind energy property, and qualified fuel cell power plants. 

The credit for any fuel cell may not exceed $500 for each 0.5 kilowatt of capacity. 

The credit is nonrefundable. The credit with respect to all qualifying property may be 

claimed against the alternative minimum tax. 

The credit applies to property placed in service prior to January 1, 2017 

Qualified property

Qualified solar electric property is property that uses solar energy to generate electricity 

for use in a dwelling unit. Qualifying solar water heating property is property used to heat water 

for use in a dwelling unit located in the United States and used as a residence if at least half of 

the energy used by such property for such purpose is derived from the sun. 

A qualified fuel cell power plant is an integrated system comprised of a fuel cell stack 

assembly and associated balance of plant components that (1) converts a fuel into electricity 

using electrochemical means, (2) has an electricity-only generation efficiency of greater than 30 

percent, and (3) has a nameplate capacity of at least one-half kilowatt. The qualified fuel cell 

power plant must be installed on or in connection with a dwelling unit located in the United 

States and used by the taxpayer as a principal residence. 

Qualified small wind energy property is property that uses a wind turbine to generate 

electricity for use in a dwelling unit located in the U.S. and used as a residence by the taxpayer. 

Qualified geothermal heat pump property means any equipment which (1) uses the 

ground or ground water as a thermal energy source to heat the dwelling unit or as a thermal 

energy sink to cool such dwelling unit, (2) meets the requirements of the Energy Star program 

which are in effect at the time that the expenditure for such equipment is made, and (3) is 
51 

installed on or in connection with a dwelling unit located in the United States and used as a 

residence by the taxpayer. 

Additional rules

The depreciable basis of the property is reduced by the amount of the credit. 

Expenditures for labor costs allocable to onsite preparation, assembly, or original installation of 

property eligible for the credit are eligible expenditures. 

Special proration rules apply in the case of jointly owned property, condominiums, and 

tenant-stockholders in cooperative housing corporations. If less than 80 percent of the property 

is used for nonbusiness purposes, only that portion of expenditures that is used for nonbusiness 

purposes is taken into account. 

3. Alternative and plug-in electric-drive motor vehicle credits (secs. 30, 30B, and 30D) 

Present Law

Alternative motor vehicle credit (sec. 30B)

A credit is available for each new qualified fuel cell vehicle, hybrid vehicle, advanced 

lean burn technology vehicle, and alternative fuel vehicle placed in service by the taxpayer 

during the taxable year.60 In general, the credit amount varies depending upon the type of 

technology used, the weight class of the vehicle, the amount by which the vehicle exceeds 

certain fuel economy standards, and, for some vehicles, the estimated lifetime fuel savings. The 

credit generally is available for vehicles purchased after 2005. The credit terminates after 2009, 

2010, or 2014, depending on the type of vehicle. 

In general, the credit is allowed to the vehicle owner, including the lessor of a vehicle 

subject to a lease. If the use of the vehicle is described in paragraphs (3) or (4) of section 50(b) 

(relating to use by tax-exempt organizations, governments, and foreign persons) and is not 

subject to a lease, the seller of the vehicle may claim the credit so long as the seller clearly 

discloses to the user in a document the amount that is allowable as a credit. A vehicle must be 

used predominantly in the United States to qualify for the credit. The portion of the credit 

attributable to vehicles of a character subject to an allowance for depreciation is treated as a 

portion of the general business credit. 

Fuel cell vehicles

A qualified fuel cell vehicle is a motor vehicle that is propelled by power derived from 

one or more cells that convert chemical energy directly into electricity by combining oxygen 

with hydrogen fuel that is stored on board the vehicle and may or may not require reformation 

prior to use. A qualified fuel cell vehicle must be purchased before January 1, 2015. The amount 

of credit for the purchase of a fuel cell vehicle is determined by a base credit amount that 

 60 Sec. 30B. 
52 

depends upon the weight class of the vehicle and, in the case of automobiles or light trucks, an 

additional credit amount that depends upon the rated fuel economy of the vehicle compared to a 

base fuel economy. For these purposes the base fuel economy is the 2002 model year city fuel 

economy rating for vehicles of various weight classes.61 Table 2, below, shows the base credit 

amounts. 

Table 2.–Base Credit Amount for Fuel Cell Vehicles 

Vehicle Gross Weight Rating (pounds) Credit Amount 

Vehicle ≤ 8,500 $8,000 

8,500 < vehicle ≤ 14,000 $10,000 

14,000 < vehicle ≤ 26,000 $20,000 

26,000 < vehicle $40,000 

In the case of a fuel cell vehicle weighing less than 8,500 pounds and placed in service 

after December 31, 2009, the $8,000 amount in Table 2, above is reduced to $4,000. 

Table 3, below, shows the additional credits for passenger automobiles or light trucks. 

Table 3.–Credit for Qualified Fuel Cell Vehicles 

Credit 

If Fuel Economy of the Fuel Cell Vehicle Is: 

at least but less than 

$1,000 150% of base fuel economy 175% of base fuel economy 

$1,500 175% of base fuel economy 200% of base fuel economy 

$2,000 200% of base fuel economy 225% of base fuel economy 

$2,500 225% of base fuel economy 250% of base fuel economy 

$3,000 250% of base fuel economy 275% of base fuel economy 

$3,500 275% of base fuel economy 300% of base fuel economy 

$4,000 300% of base fuel economy 

 61 See discussion surrounding Table 7, below. 
53 

Hybrid vehicles and advanced lean burn technology vehicles

Qualified hybrid vehicles

A qualified hybrid vehicle is a motor vehicle that draws propulsion energy from on-board 

sources of stored energy that include both an internal combustion engine or heat engine using 

combustible fuel and a rechargeable energy storage system (e.g., batteries). A qualified hybrid 

vehicle must be placed in service before January 1, 2011 (January 1, 2010 in the case of a hybrid 

vehicle weighing more than 8,500 pounds). 

Hybrid vehicles that are automobiles and light trucks

In the case of an automobile or light truck (vehicles weighing 8,500 pounds or less), the 

amount of credit for the purchase of a hybrid vehicle is the sum of two components: (1) a fuel 

economy credit amount that varies with the rated fuel economy of the vehicle compared to a 

2002 model year standard and (2) a conservation credit based on the estimated lifetime fuel 

savings of the qualified vehicle compared to a comparable 2002 model year vehicle that is 

powered solely by a gasoline or diesel internal combustion engine. A qualified hybrid 

automobile or light truck must have a maximum available power62 from the rechargeable energy 

storage system of at least four percent. In addition, the vehicle must meet or exceed certain 

Environmental Protection Agency (“EPA”) emissions standards. For a vehicle with a gross 

vehicle weight rating of 6,000 pounds or less, the applicable emissions standards are the Bin 5 

Tier II emissions standards. For a vehicle with a gross vehicle weight rating greater than 6,000 

pounds and less than or equal to 8,500 pounds, the applicable emissions standards are the Bin 8 

Tier II emissions standards. 

Table 4, below, shows the fuel economy credit available to a hybrid passenger 

automobile or light truck whose fuel economy (on a gasoline gallon equivalent basis) exceeds 

that of a base fuel economy. 

Table 4.–Fuel Economy Credit 

 If Fuel Economy of the Hybrid Vehicle Is: 

Credit at least but less than 

 $400 125% of base fuel economy 150% of base fuel economy 

 $800 150% of base fuel economy 175% of base fuel economy 

 $1,200 175% of base fuel economy 200% of base fuel economy 

 $1,600 200% of base fuel economy 225% of base fuel economy 

 $2,000 225% of base fuel economy 250% of base fuel economy 

 $2,400 250% of base fuel economy 

 62 For hybrid passenger vehicles and light trucks, the term “maximum available power” means 

the maximum power available from the rechargeable energy storage system, during a standard 10 second 

pulse power or equivalent test, divided by such maximum power and the SAE net power of the heat 

engine. Sec. 30B(d)(3)(C)(i). 
54 

Table 5, below, shows the conservation credit. 

Table 5.–Conservation Credit 

Estimated Lifetime Fuel Savings 

(gallons of gasoline) Conservation Amount 

At least 1,200 but less than 1,800 $250 

At least 1,800 but less than 2,400 $500 

At least 2,400 but less than 3,000 $750 

At least 3,000 $1,000 

Advanced lean burn technology vehicles

The amount of credit for the purchase of an advanced lean burn technology vehicle is the 

sum of two components: (1) a fuel economy credit amount that varies with the rated fuel 

economy of the vehicle compared to a 2002 model year standard as described in Table 4, above, 

and (2) a conservation credit based on the estimated lifetime fuel savings of a qualified vehicle 

compared to a comparable 2002 model year vehicle as described in Table 5, above. The amounts 

of the credits are determined after an adjustment is made to account for the different BTU 

content of gasoline and the fuel utilized by the lean burn technology vehicle. 

A qualified advanced lean burn technology vehicle is a passenger automobile or a light 

truck that incorporates direct injection, achieves at least 125 percent of the 2002 model year city 

fuel economy, and for 2004 and later model vehicles meets or exceeds certain Environmental 

Protection Agency emissions standards. For a vehicle with a gross vehicle weight rating of 

6,000 pounds or less the applicable emissions standards are the Bin 5 Tier II emissions standards. 

For a vehicle with a gross vehicle weight rating greater than 6,000 pounds and less than or equal 

to 8,500 pounds, the applicable emissions standards are the Bin 8 Tier II emissions standards. A 

qualified advanced lean burn technology vehicle must be placed in service before January 1, 

2011. 

Limitation on number of qualified hybrid and advanced lean burn technology vehicles 

eligible for the credit

There is a limitation on the number of passenger and light truck qualified hybrid vehicles 

and advanced lean burn technology vehicles sold by each manufacturer of such vehicles that are 

eligible for the credit. Taxpayers may claim the full amount of the allowable credit up to the end 

of the first calendar quarter after the quarter in which the manufacturer records the 60,000th 

hybrid and advanced lean burn technology vehicle sale occurring after December 31, 2005. 

Taxpayers may claim one half of the otherwise allowable credit during the two calendar quarters 

subsequent to the first quarter after the manufacturer has recorded its 60,000th such sale. In the 

third and fourth calendar quarters subsequent to the first quarter after the manufacturer has 

recorded its 60,000th such sale, the taxpayer may claim one quarter of the otherwise allowable 

credit. 
55 

Thus, for example, summing the sales of qualified hybrid vehicles that are passenger 

vehicles or light trucks and all sales of qualified advanced lean burn technology vehicles, if a 

manufacturer records the sale of its 60,000th qualified vehicle in February of 2007, taxpayers 

purchasing such vehicles from the manufacturer may claim the full amount of the credit on their 

purchases of qualified vehicles through June 30, 2007. For the period July 1, 2007, through 

December 31, 2007, taxpayers may claim one half of the otherwise allowable credit on purchases 

of qualified vehicles of the manufacturer. For the period January 1, 2008, through June 30, 

2008, taxpayers may claim one quarter of the otherwise allowable credit on the purchases of 

qualified vehicles of the manufacturer. After June 30, 2008, no credit may be claimed for 

purchases of such hybrid vehicles or advanced lean burn technology vehicles sold by the 

manufacturer. 

Hybrid vehicles that are medium and heavy trucks

In the case of a qualified hybrid vehicle weighing more than 8,500 pounds, the amount of 

credit is determined by the estimated increase in fuel economy and the incremental cost of the 

hybrid vehicle compared to a comparable vehicle powered solely by a gasoline or diesel internal 

combustion engine and that is comparable in weight, size, and use of the vehicle. For a vehicle 

that achieves a fuel economy increase of at least 30 percent but less than 40 percent, the credit is 

equal to 20 percent of the incremental cost of the hybrid vehicle. For a vehicle that achieves a 

fuel economy increase of at least 40 percent but less than 50 percent, the credit is equal to 30 

percent of the incremental cost of the hybrid vehicle. For a vehicle that achieves a fuel economy 

increase of 50 percent or more, the credit is equal to 40 percent of the incremental cost of the 

hybrid vehicle. 

The credit is subject to certain maximum applicable incremental cost amounts. For a 

qualified hybrid vehicle weighing more than 8,500 pounds but not more than 14,000 pounds, the 

maximum allowable incremental cost amount is $7,500. For a qualified hybrid vehicle weighing 

more than 14,000 pounds but not more than 26,000 pounds, the maximum allowable incremental 

cost amount is $15,000. For a qualified hybrid vehicle weighing more than 26,000 pounds, the 

maximum allowable incremental cost amount is $30,000. 

A qualified hybrid vehicle weighing more than 8,500 pounds but not more than 14,000 

pounds must have a maximum available power from the rechargeable energy storage system of 

at least 10 percent. A qualified hybrid vehicle weighing more than 14,000 pounds must have a 

maximum available power from the rechargeable energy storage system of at least 15 percent.63

 63 In the case of such heavy-duty hybrid motor vehicles, the percentage of maximum available 

power is computed by dividing the maximum power available from the rechargeable energy storage 

system during a standard 10-second pulse power test, divided by the vehicle’s total traction power. A 

vehicle’s total traction power is the sum of the peak power from the rechargeable energy storage system 

and the heat (e.g., internal combustion or diesel) engine’s peak power. If the rechargeable energy storage 

system is the sole means by which the vehicle can be driven, then the total traction power is the peak 

power of the rechargeable energy storage system. 
56 

Alternative fuel vehicle

The credit for the purchase of a new alternative fuel vehicle is 50 percent of the 

incremental cost of such vehicle, plus an additional 30 percent if the vehicle meets certain 

emissions standards. The incremental cost of any new qualified alternative fuel vehicle is the 

excess of the manufacturer’s suggested retail price for such vehicle over the price for a gasoline 

or diesel fuel vehicle of the same model. To be eligible for the credit, a qualified alternative fuel 

vehicle must be purchased before January 1, 2011. 

The amount of the credit varies depending on the weight of the qualified vehicle. The 

credit is subject to certain maximum applicable incremental cost amounts. Table 6, below, 

shows the maximum permitted incremental cost for the purpose of calculating the credit for 

alternative fuel vehicles by vehicle weight class as well as the maximum credit amount for such 

vehicles. 

Table 6.–Maximum Allowable Incremental Cost for Calculation 

of Alternative Fuel Vehicle Credit 

Vehicle Gross Weight Rating (pounds) Maximum Allowable 

Incremental Cost 

Maximum 

Allowable Credit 

Vehicle ≤ 8,500 $5,000 $4,000 

8,500 < vehicle ≤ 14,000 $10,000 $8,000 

14,000 < vehicle ≤ 26,000 $25,000 $20,000 

26,000 < vehicle $40,000 $32,000 

Alternative fuels comprise compressed natural gas, liquefied natural gas, liquefied 

petroleum gas, hydrogen, and any liquid fuel that is at least 85 percent methanol. Qualified 

alternative fuel vehicles are vehicles that operate only on qualified alternative fuels and are 

incapable of operating on gasoline or diesel (except to the extent gasoline or diesel fuel is part of 

a qualified mixed fuel, described below). 

Certain mixed fuel vehicles, that is vehicles that use a combination of an alternative fuel 

and a petroleum-based fuel, are eligible for a reduced credit. If the vehicle operates on a mixed 

fuel that is at least 75 percent alternative fuel, the vehicle is eligible for 70 percent of the 

otherwise allowable alternative fuel vehicle credit. If the vehicle operates on a mixed fuel that is 

at least 90 percent alternative fuel, the vehicle is eligible for 90 percent of the otherwise 

allowable alternative fuel vehicle credit. 

Base fuel economy

The base fuel economy is the 2002 model year city fuel economy by vehicle type and 

vehicle inertia weight class. For this purpose, “vehicle inertia weight class” has the same 

meaning as when defined in regulations prescribed by the EPA for purposes of Title II of the 
57 

Clean Air Act. Table 7, below, shows the 2002 model year city fuel economy for vehicles by 

type and by inertia weight class. 

Table 7.–2002 Model Year City Fuel Economy 

Vehicle Inertia 

Weight Class 

(pounds) 

Passenger Automobile 

(miles per gallon) 

Light Truck 

(miles per gallon) 

1,500 45.2 39.4 

1,750 45.2 39.4 

2,000 39.6 35.2 

2,250 35.2 31.8 

2,500 31.7 29.0 

2,750 28.8 26.8 

3,000 26.4 24.9 

3,500 22.6 21.8 

4,000 19.8 19.4 

4,500 17.6 17.6 

5,000 15.9 16.1 

5,500 14.4 14.8 

6,000 13.2 13.7 

6,500 12.2 12.8 

7,000 11.3 12.1 

8,500 11.3 12.1 

Plug-in electric-drive motor vehicle credit (sec. 30D)

Rules for taxable years beginning after December 31, 2008, with respect to vehicles 

acquired in that taxable year and before January 1, 2010 

A credit is available for each qualified plug-in electric-drive motor vehicle placed in 

service. A qualified plug-in electric-drive motor vehicle is a motor vehicle that has at least four 

wheels, is manufactured for use on public roads, meets certain emissions standards (except for 

certain heavy vehicles), draws propulsion using a traction battery with at least four kilowatthours of capacity, and is capable of being recharged from an external source of electricity. 
58 

The base amount of the plug-in electric-drive motor vehicle credit is $2,500, plus another 

$417 for each kilowatt-hour of battery capacity in excess of four kilowatt-hours. The maximum 

credit for qualified vehicles weighing 10,000 pounds or less is $7,500. This maximum amount 

increases to $10,000 for vehicles weighing more than 10,000 pounds but not more than 14,000 

pounds, to $12,500 for vehicles weighing more than 14,000 pounds but not more than 26,000 

pounds, and to $15,000 for vehicle weighing more than 26,000 pounds. 

In general, the credit is available to the vehicle owner, including the lessor of a vehicle 

subject to lease. If the qualified vehicle is used by certain tax-exempt organizations, 

governments, or foreign persons and is not subject to a lease, the seller of the vehicle may claim 

the credit so long as the seller clearly discloses to the user in a document the amount that is 

allowable as a credit. A vehicle must be used predominantly in the United States to qualify for 

the credit. 

Once a total of 250,000 credit-eligible vehicles have been sold for use in the United 

States, the credit phases out over four calendar quarters. The phaseout period begins in the 

second calendar quarter following the quarter during which the vehicle cap has been reached. 

Taxpayers may claim one-half of the otherwise allowable credit during the first two calendar 

quarters of the phaseout period and twenty-five percent of the otherwise allowable credit during 

the next two quarters. After this, no credit is available. 

The basis of any qualified vehicle is reduced by the amount of the credit. To the extent a 

vehicle is eligible for credit as a qualified plug-in electric-drive motor vehicle, it is not eligible 

for credit as a qualified hybrid vehicle under section 30B. The portion of the credit attributable 

to vehicles of a character subject to an allowance for depreciation is treated as part of the general 

business credit; the nonbusiness portion of the credit is allowable to the extent of the excess of 

the regular tax over the alternative minimum tax (reduced by certain other credits) for the taxable 

year. 

Rules for vehicles acquired after December 31, 2009

For plug-in electric drive vehicles acquired after December 31, 2009, the maximum credit 

is capped at $7,500 regardless of vehicle weight. In addition, after that date no credit is available 

for low speed plug-in vehicles or for plug-in vehicles weighing 14,000 pounds or more. 

After December 31, 2009, the 250,000 total plug-in vehicle limitation is replaced with a 

200,000 plug-in vehicles per manufacturer limitation. Under the new limitation, the credit 

phases out over four calendar quarters beginning in the second calendar quarter following the 

quarter in which the manufacturer limit is reached. 

Credit for electric-drive low-speed vehicles, motorcycles, and three-wheeled vehicles (sec. 

30)

A 10-percent credit for low-speed vehicles, motorcycles, and three-wheeled vehicles is 

available for vehicles that, generally, would otherwise meet the criteria of a qualified plug-in 

electric-drive motor vehicle but for the fact that they are low-speed vehicles or do not have at 

least four wheels. Two or three wheeled vehicles must have a battery capacity of at least 2.5 

kilowatt-hours. Other vehicles must have a battery capacity of at least 4 kilowatt-hours. The 
59 

maximum credit for such vehicles is $2,500. The credit is part of the general business credit. 

The credit is available for vehicles acquired after February 17, 2009 (the date of enactment of the 

American Recovery and Reinvestment Act of 2009), and before January 1, 2012. 

Credit for converting a vehicle into a plug-in electric-drive motor vehicle (sec. 30B)

A 10-percent credit, up to $4,000, is available for the cost of converting any motor 

vehicle into a qualified plug-in electric-drive motor vehicle. To be eligible for the credit, a 

qualified plug-in traction battery module must have a capacity of at least 4 kilowatt-hours. The 

credit is available for conversions made after February 17, 2009 (the date of enactment of the 

American Recovery and Reinvestment Act of 2009), and before January 1, 2012. 

4. New energy efficient home credit (sec 45L of the Code) 

The new energy efficient home credit is available to an eligible contractor for the 

construction of a qualified new energy-efficient home. To qualify as a new energy-efficient 

home, the home must be: (1) a dwelling located in the United States, (2) substantially completed 

after August 8, 2005, and (3) certified in accordance with guidance prescribed by the Secretary 

to achieve either a 30-percent or 50-percent reduction in heating and cooling energy 

consumption compared to a comparable dwelling constructed in accordance with the standards of 

chapter 4 of the 2003 International Energy Conservation Code as in effect (including 

supplements) on August 8, 2005, and any applicable Federal minimum efficiency standards for 

heating and cooling equipment. 

The credit equals $1,000 in the case of a new home that meets the 30 percent standard 

and $2,000 in the case of a new home that meets the 50 percent standard. 

With respect to homes that meet the 30-percent standard, one-third of such 30 percent 

savings must come from the building envelope, and with respect to homes that meet the 50-

percent standard, one-fifth of such 50 percent savings must come from the building envelope. 

Only manufactured homes are eligible for the $1,000 credit. In lieu of meeting the 30 

percent efficiency improvement relative to the standards of chapter 4 of the 2003 International 

Energy Conservation Code, manufactured homes certified by a method prescribed by the 

Administrator of the Environmental Protection Agency under the Energy Star Labeled Homes 

program are eligible for the $1,000 credit provided criteria (1) and (2), above, are met. 

Manufactured homes are homes that conform to Federal manufactured home construction 

and safety standards. The eligible contractor is the person who constructed the home, or in the 

case of a manufactured home, the producer of such home. The credit is part of the general 

business credit. 

The credit applies to homes acquired prior to January 1, 2010. 
60 

5. Energy efficient appliance credit (sec. 45M of the Code) 

In general

A credit is allowed for the eligible production of certain energy-efficient dishwashers, 

clothes washers, and refrigerators. The credit is part of the general business credit. 

The credits are as follows: 

Dishwashers

$45 in the case of a dishwasher that is manufactured in calendar year 2008 or 2009 that 

uses no more than 324 kilowatt hours per year and 5.8 gallons per cycle, and 

$75 in the case of a dishwasher that is manufactured in calendar year 2008, 2009, or 2010 

and that uses no more than 307 kilowatt hours per year and 5.0 gallons per cycle (5.5 gallons per 

cycle for dishwashers designed for greater than 12 place settings). 

Clothes washers

$75 in the case of a residential top-loading clothes washer manufactured in calendar year 

2008 that meets or exceeds a 1.72 modified energy factor and does not exceed a 8.0 water 

consumption factor, and 

$125 in the case of a residential top-loading clothes washer manufactured in calendar 

year 2008 or 2009 that meets or exceeds a 1.8 modified energy factor and does not exceed a 7.5 

water consumption factor, 

$150 in the case of a residential or commercial clothes washer manufactured in calendar 

year 2008, 2009 or 2010 that meets or exceeds a 2.0 modified energy factor and does not exceed 

a 6.0 water consumption factor, and 

$250 in the case of a residential or commercial clothes washer manufactured in calendar 

year 2008, 2009, or 2010 that meets or exceeds a 2.2 modified energy factor and does not exceed 

a 4.5 water consumption factor. 

Refrigerators

$50 in the case of a refrigerator manufactured in calendar year 2008 that consumes at 

least 20 percent but not more than 22.9 percent less kilowatt hours per year than the 2001 energy 

conservation standards, 

$75 in the case of a refrigerator that is manufactured in calendar year 2008 or 2009 that 

consumes at least 23 percent but no more than 24.9 percent less kilowatt hours per year than the 

2001 energy conservation standards, 
61 

$100 in the case of a refrigerator that is manufactured in calendar year 2008, 2009 or 

2010 that consumes at least 25 percent but not more than 29.9 percent less kilowatt hours per 

year than the 2001 energy conservation standards, and 

$200 in the case of a refrigerator manufactured in calendar year 2008, 2009 or 2010 that 

consumes at least 30 percent less energy than the 2001 energy conservation standards. 

Definitions

A dishwasher is any residential dishwasher subject to the energy conservation standards 

established by the Department of Energy. A refrigerator must be an automatic defrost 

refrigerator-freezer with an internal volume of at least 16.5 cubic feet to qualify for the credit. A 

clothes washer is any residential clothes washer, including a residential style coin operated 

washer, that satisfies the relevant efficiency standard. 

The term “modified energy factor” means the modified energy factor established by the 

Department of Energy for compliance with the Federal energy conservation standard. 

The term “gallons per cycle” means, with respect to a dishwasher, the amount of water, 

expressed in gallons, required to complete a normal cycle of a dishwasher. 

The term “water consumption factor” means, with respect to a clothes washer, the 

quotient of the total weighted per-cycle water consumption divided by the cubic foot (or liter) 

capacity of the clothes washer. 

Other rules

Appliances eligible for the credit include only those produced in the United States and 

that exceed the average amount of U.S. production from the two prior calendar years for each 

category of appliance. The aggregate credit amount allowed with respect to a taxpayer for all 

taxable years beginning after December 31, 2007 may not exceed $75 million, with the exception 

that the $200 refrigerator credit and the $250 clothes washer credit are not limited. Additionally, 

the credit allowed in a taxable year for all appliances may not exceed two percent of the average 

annual gross receipts of the taxpayer for the three taxable years preceding the taxable year in 

which the credit is determined. 

6. Qualified energy conservation bonds (sec. 54D) 

Qualified Energy Conservation Bonds (“QEC bonds”) are a type of qualified tax credit 

bond for purposes of section 54A of the Code.64 QEC bonds, which are subject to a national 

volume cap of $3.2 billion65 (discussed below) generally must be issued by a State or local 

 64 Sec. 54A(d)(1)(C). 

65 The American Recovery and Reinvestment Act of 2009 increased the national volume cap to 

$3.2 billion from $800 million.
62 

government and must be designated by the issuer as a QEC bond.66 In addition, 100 percent of 

the available project proceeds of QEC bond issuance must be used for “qualified conservation 

purposes” (defined below).67 A taxpayer holding a QEC bond on a credit allowance date is 

entitled to a credit against its Federal income taxes. As discussed in more detail below, the 

annual credit with respect to a QEC bond is equal to 70 percent of the credit that the Treasury 

Secretary determines would allow the QEC bond to be issued at par and without interest. 

Because the credit is only 70 percent of the credit that would permit the QEC bond to be issued 

at par and without interest, it is assumed that QEC bonds will be interest bearing and/or issued at 

a discount. The tax credit to a holder of a QEC bond is treated as interest that is includible in the 

holder’s gross income, and any interest paid on a QEC bond is taxable.68

The term “qualified conservation purpose” means: 

1. Capital expenditures incurred for purposes of (a) reducing energy consumption in 

publicly owned buildings by at least 20 percent; (b) implementing green community 

programs (including the use of loans, grants or other repayment mechanisms to 

implement such programs); (c) rural development involving the production of 

electricity from renewable energy resources; or (d) any facility eligible for the 

production tax credit under section 45 (other than Indian coal and refined coal 

production facilities);69

2. Expenditures with respect to facilities or grants that support research in: (a) 

development of cellulosic ethanol or other nonfossil fuels; (b) technologies for the 

capture and sequestration of carbon dioxide produced through the use of fossil fuels; 

(c) increasing the efficiency of existing technologies for producing nonfossil fuels; (d) 

automobile battery technologies and other technologies to reduce fossil fuel 

consumption in transportation; and (e) technologies to reduce energy use in 

buildings;70

 66 Sec. 54D(a). In addition, eligible issuer also include entities empowered to issue bonds on 

behalf of a State or local government and otherwise eligible issuers in conduit financing issues (as defined 

in Treas. Reg. sec. 1.150-1(b)). See Notice 2009-29, 2009-17 I.R.B. (April 6, 2009). 

67 Id. 

68 Sec. 54A(f). 

69 Sec. 54D(f)(1)(A). The American Recovery and Reinvestment Act of 2009 clarified that 

capital expenditures to implement green community programs include grants, loans and other repayment 

mechanisms to implement such programs. This expansion enables States to issue QEC bonds to finance, 

for example, retrofits of existing private buildings through loans and/or grants to individual homeowners 

or businesses, or through other repayment mechanisms. Other repayment mechanisms can include 

periodic fees assessed on a government bill or utility bill that approximates the energy savings of energy 

efficiency or conservation retrofits. Retrofits can include heating, cooling, lighting, water-saving, storm 

water-reducing, or other efficiency measures. 

70 Sec. 54D(f)(1)(B). 
63 

3. Mass commuting facilities and related facilities that reduce the consumption of 

energy, including expenditures to reduce pollution from vehicles used for mass 

commuting;71 

4. Demonstration projects designed to promote the commercialization of: (a) green 

building technology; (b) conversion of agricultural waste for use in the production of 

fuel or otherwise; (c) advanced battery manufacturing technologies; (d) technologies 

to reduce peak-use of electricity; and (e) technologies for the capture and sequestration 

of carbon dioxide emitted from combusting fossil fuels in order to produce 

electricity;72 and 

5. Public education campaigns to promote energy efficiency (other than movies, 

concerts, and other events held primarily for entertainment purposes).73

There is a national limitation on QEC bonds of $3.2 billion.74 Allocations of QEC bonds 

are made to the States with sub-allocations to large local governments.75 Allocations are made to 

the States according to their respective populations, reduced by any sub-allocations to large local 

governments (defined below) within the States. Sub-allocations to large local governments shall 

be an amount of the national qualified energy conservation bond limitation that bears the same 

ratio to the amount of such limitation that otherwise would be allocated to the State in which 

such large local government is located as the population of such large local government bears to 

the population of such State. The term “large local government” means: any municipality or 

county if such municipality or county has a population of 100,000 or more. Indian tribal 

governments also are treated as large local governments for these purposes (without regard to 

population). 

Each State or large local government receiving an allocation of QEC bonds may further 

allocate issuance authority to issuers within such State or large local government. However, any 

allocations to issuers within the State or large local government must be made in a manner that 

results in not less than 70 percent of the allocation of QEC bonds to such State or large local 

government being used to designate bonds that are not private activity bonds (i.e., the bond 

cannot meet the private business tests or the private loan test of section 141); for purposes of 

applying this rule, any bond used for the purpose of providing grants, loans or other repayment 

mechanisms for capital expenditures to implement green community programs is not treated as a 

private activity bond. 

 71 Sec. 54D(f)(1)(C). 

72 Sec. 54D(f)(1)(D). 

73 Sec. 54D(f)(1)(E). 

74 Sec. 54D(d). 

75 See generally, Sec. 54D(e). See also Notice 2009-29 for 2009 (listing allocations to States of 

the national QEC bond volume cap). 
64 

In the case of QEC bonds issued as private activity bonds, 100 percent of the available 

project proceeds must be used for capital expenditures76. In addition, QEC bonds only may be 

issued by Indian tribal governments to the extent such bonds are issued for purposes that satisfy 

the present law requirements for tax-exempt bonds issued by Indian tribal governments (i.e., 

essential governmental functions and certain manufacturing purposes).77 

One-hundred percent of the available project proceeds with respect to an issuance of 

QEC bonds must be used within the three-year period that begins on the date of issuance.78 

Available project proceeds are proceeds from the sale of the issue less issuance costs (not to 

exceed two percent) and any investment earnings on such sale proceeds. To the extent that less 

than 100 percent of the available project proceeds with respect to an issuance of QEC bonds are 

used to finance qualified conservation purposes during the three-year spending period, such 

bonds will continue to qualify as QEC bonds if unspent proceeds are used within 90 days from 

the end of such three-year period to redeem such bonds. The three-year spending period may be 

extended by the Secretary upon the issuer’s request if the issuer establishes that the failure to 

satisfy the three-year requirement is due to reasonable cause and the qualified expenditures will 

continue to proceed with due diligence. 

QEC bonds generally are subject to the arbitrage requirements of section 148.79 

However, available project proceeds invested during the three-year spending period are not 

subject to the arbitrage restrictions (i.e., yield restriction and rebate requirements). In addition, 

amounts invested in a reserve fund are not subject to the arbitrage restrictions to the extent: (1) 

such fund is funded at a rate not more rapid than equal annual installments; (2) such fund is 

funded in a manner reasonably expected to result in an amount not greater than an amount 

necessary to repay the issue; and (3) the yield on such fund is not greater than the average annual 

interest rate of tax-exempt obligations having a term of 10 years or more that are issued during 

the month the QEC bonds are issued. 

The maturity of QEC bonds is the term that the Secretary estimates will result in the 

present value of the obligation to repay the principal on such bonds being equal to 50 percent of 

the face amount of such bonds, using as a discount rate the average annual interest rate of taxexempt obligations having a term of 10 years or more that are issued during the month the QEC 

bonds are issued.80 

As with other tax credit bonds, the taxpayer holding QEC bonds on a credit allowance 

date is entitled to a tax credit.81 The credit rate on the bonds is set by the Secretary at a rate that 

 76 Sec. 54D(f)(2). 

77 Sec. 54D(h). 

78 Sec. 54A(d)(2). 

79 Sec. 54A(d)(4). 

80 Sec. 54A(d)(5). 

81 Sec. 54D(b) and Sec. 54A(b). 
65 

is 70 percent of the rate that would permit issuance of such bonds without discount and interest 

cost to the issuer.82 The Secretary determines credit rates for tax credit bonds based on general 

assumptions about credit quality of the class of potential eligible issuers and such other factors as 

the Secretary deems appropriate. The Secretary may determine credit rates based on general 

credit market yield indexes and credit ratings.83 The amount of the tax credit is determined by 

multiplying the bond’s credit rate by the face amount on the holder’s bond. The credit accrues 

quarterly, is includible in gross income (as if it were an interest payment on the bond), and can 

be claimed against regular income tax liability and alternative minimum tax liability. Unused 

credits may be carried forward to succeeding taxable years. In addition, credits may be separated 

from the ownership of the underlying bond similar to how interest coupons can be stripped for 

interest-bearing bonds. 

Issuers of QEC bonds are required to certify that the financial disclosure requirements 

that applicable State and local law requirements governing conflicts of interest are satisfied with 

respect to such issue, as well as any other additional conflict of interest rules prescribed by the 

Secretary with respect to any Federal, State, or local government official directly involved with 

the issuance of QEC bonds. 

The following table provides the allocation to States of the National Bond Volume cap 

for qualified energy conservation bonds. 

 82 Given the differences in credit quality and other characteristics of individual issuers, the 

Secretary cannot set credit rates in a manner that will allow each issuer to issue tax credit bonds at par. 

83 See Internal Revenue Service, Notice 2009-15, Credit Rates on Tax Credit Bonds, 2009-6 IRB 

1 (January 22, 2009). 
66 

Table 8.−Allocations to States of the National Bond Volume Cap 

for Qualified Energy Conservations Bonds 

State or Territory QEC Bond Allocations 

(in dollars) 

Alabama 48,364,000 

Alaska 7,120,000 

Arizona 67,436,000 

Arkansas 29,623,000 

California 381,329,000 

Colorado 51,244,000 

Connecticut 36,323,000 

Delaware 9,058,000 

District of Columbia 6,140,000 

Florida 190,146,000 

Georgia 100,484,000 

Hawaii 13,364,000 

Idaho 15,809,000 

Illinois 133,846,000 

Indiana 66,155,000 

Iowa 31,150,000 

Kansas 29,070,000 

Kentucky 44,291,000 

Louisiana 45,759,000 

Maine 13,657,000 

Maryland 58,445,000 

Massachusetts 67,413,000 

Michigan 103,780,000 

Minnesota 54,159,000 

Mississippi 30,486,000 

Missouri 61,329,000 
67 

Table 8.−Allocations to States of the National Bond Volume Cap 

for Qualified Energy Conservations Bonds 

State or Territory QEC Bond Allocations 

(in dollars) 

Montana 10,037,000 

Nebraska 18,502,000 

Nevada 26,975,000 

New Hampshire 13,651,000 

New Jersey 90,078,000 

New Mexico 20,587,000 

New York 202,200,000 

North Carolina 95,677,000 

North Dakota 6,655,000 

Ohio 119,160,000 

Oklahoma 37,787,000 

Oregon 39,320,000 

Pennsylvania 129,144,000 

Rhode Island 10,901,000 

South Carolina 46,475,000 

South Dakota 8,343,000 

Tennessee 64,476,000 

Texas 252,378,000 

Utah 28,389,000 

Vermont 6,445,000 

Virginia 80,600,000 

Washington 67,944,000 

West Virginia 18,824,000 

Wisconsin 58,387,000 

Wyoming 5,526,000 

 
68 

Table 8.−Allocations to States of the National Bond Volume Cap 

for Qualified Energy Conservations Bonds 

State or Territory QEC Bond Allocations 

(in dollars) 

American Samoa 673,000 

Guam 1,826,000 

Northern Marianas 899,000 

Puerto Rico 41,021,000 

US Virgin Islands 1,140,000 

 

Total Allocation 3,200,000,000 

7. Energy efficient commercial buildings deduction (sec. 179D) 

In general

Code section 179D provides a deduction equal to energy-efficient commercial building 

property expenditures made by the taxpayer. Energy-efficient commercial building property 

expenditures are defined as property (1) which is installed on or in any building located in the 

United States that is within the scope of Standard 90.1-2001 of the American Society of Heating, 

Refrigerating, and Air Conditioning Engineers and the Illuminating Engineering Society of 

North America (“ASHRAE/IESNA”), (2) which is installed as part of (i) the interior lighting 

systems, (ii) the heating, cooling, ventilation, and hot water systems, or (iii) the building 

envelope, and (3) which is certified as being installed as part of a plan designed to reduce the 

total annual energy and power costs with respect to the interior lighting systems, heating, 

cooling, ventilation, and hot water systems of the building by 50 percent or more in comparison 

to a reference building which meets the minimum requirements of Standard 90.1-2001 (as in 

effect on April 2, 2003). The deduction is limited to an amount equal to $1.80 per square foot of 

the property for which such expenditures are made. The deduction is allowed in the year in 

which the property is placed in service. 

Certain certification requirements must be met in order to qualify for the deduction. The 

Secretary, in consultation with the Secretary of Energy, will promulgate regulations that describe 

methods of calculating and verifying energy and power costs using qualified computer software 

based on the provisions of the 2005 California Nonresidential Alternative Calculation Method 

Approval Manual or, in the case of residential property, the 2005 California Residential 

Alternative Calculation Method Approval Manual. 

The Secretary is granted authority to prescribe procedures for the inspection and testing 

for compliance of buildings that are comparable, given the difference between commercial and 
69 

residential buildings, to the requirements in the Mortgage Industry National Accreditation 

Procedures for Home Energy Rating Systems.84 Individuals qualified to determine compliance 

shall only be those recognized by one or more organizations certified by the Secretary for such 

purposes. 

For energy-efficient commercial building property expenditures made by a public entity, 

such as public schools, the Secretary shall promulgate regulations that allow the deduction to be 

allocated to the person primarily responsible for designing the property in lieu of the public 

entity. 

If a deduction is allowed under this section, the basis of the property shall be reduced by 

the amount of the deduction. 

The deduction is effective for property placed in service prior to January 1, 2014. 

Partial allowance of deduction

In the case of a building that does not meet the overall building requirement of a 50-

percent energy savings, a partial deduction is allowed with respect to each separate building 

system that comprises energy efficient property and which is certified by a qualified professional 

as meeting or exceeding the applicable system-specific savings targets established by the 

Secretary of the Treasury. The applicable system-specific savings targets to be established by 

the Secretary are those that would result in a total annual energy savings with respect to the 

whole building of 50 percent, if each of the separate systems met the system specific target. The 

separate building systems are (1) the interior lighting system, (2) the heating, cooling, ventilation 

and hot water systems, and (3) the building envelope. The maximum allowable deduction is 

$0.60 per square foot for each separate system. 

Interim rules for lighting systems

In general, in the case of system-specific partial deductions, no deduction is allowed until 

the Secretary establishes system-specific targets.85 However, in the case of lighting system 

retrofits, until such time as the Secretary issues final regulations, the system-specific energy 

savings target for the lighting system is deemed to be met by a reduction in Lighting Power 

Density of 40 percent (50 percent in the case of a warehouse) of the minimum requirements in 

Table 9.3.1.1 or Table 9.3.1.2 of ASHRAE/IESNA Standard 90.1-2001. Also, in the case of a 

lighting system that reduces lighting power density by 25 percent, a partial deduction of 30 cents 

per square foot is allowed. A pro-rated partial deduction is allowed in the case of a lighting 

system that reduces lighting power density between 25 percent and 40 percent. Certain lighting 

 84 See IRS notice 2006-52 and 2008-40. 

85 IRS Notice 2008-40 has set a target of a 10 percent reduction in total energy and power costs 

with respect to the building envelope, and 20 percent each with respect to the interior lighting system and 

the heating, cooling, ventilation and hot water systems. 
70 

level and lighting control requirements must also be met in order to qualify for the partial 

lighting deductions under the interim rule. 

8. Energy Conservation Subsidies Provided by Public Utilities (sec. 136) 

An exclusion from gross income is provided for the value of any subsidy provided by a 

public utility to a customer for the purchase or installation of any energy conservation measure, 

meaning any installation or modification primarily designed to reduce consumption of electricity 

or natural gas or to improve the management of energy demand with respect to a dwelling unit. 

No deduction or credit is allowed for any expenditure to the extent of the exclusion taken 

for any subsidy received, and the adjusted basis of the property is reduced by the amount 

excluded. 

A “public utility” means a person engaged in the sale of electricity or natural gas to 

residential, commercial, or industrial customers for use by such customers, and such term 

includes the Federal Government, a State or local government, or any political subdivision or 

instrumentality thereof. The exclusion does not apply with respect to any payment to or from a 

qualified cogeneration facility or qualifying small power production facility pursuant to section 

210 of the Public Utility Regulatory Policy Act of 1978. 
71 

C. Provisions Relating to Fossil Fuel Extraction 

1. Credit for enhanced oil recovery costs (sec. 43)

Taxpayers may claim a credit equal to 15 percent of enhanced oil recovery (“EOR”) 

costs.86 Qualified EOR costs include the following costs associated with an EOR project. An 

EOR project is generally a project that involves the use of one or more tertiary recovery methods 

(as defined in section 193(b)(3)) to increase the amount of recoverable domestic crude oil. 

Qualified costs include (1) amounts paid for depreciable tangible property; (2) intangible drilling 

and development expenses; (3) tertiary injectant expenses; and (4) construction costs for certain 

Alaskan natural gas treatment facilities. 

The EOR credit is ratably reduced over a $6 phase-out range when the reference price for 

domestic crude oil exceeds $28 per barrel (adjusted for inflation after 1991). The reference price 

is determined based on the annual average price of domestic crude oil for the calendar year 

preceding the calendar year in which the taxable year begins.87 The EOR credit is currently 

phased-out. 

Taxpayers claiming the EOR credit must reduce by the amount of the credit any 

otherwise allowable deductions associated with EOR costs. In addition, to the extent a 

property’s basis would otherwise be increased by any EOR costs, such basis is reduced by the 

amount of the EOR credit. 

2. Credit for the production of Indian coal (sec. 45) 

A credit is available for the production of Indian coal sold to an unrelated third party 

from a qualified facility for a seven-year period beginning January 1, 2006, and ending 

December 31, 2012. The amount of the credit for Indian coal is $1.50 per ton for the first four 

years of the seven-year period and $2.00 per ton for the last three years of the seven-year period. 

Beginning in calendar years after 2006, the credit amounts are indexed annually for inflation 

using 2005 as the base year. 

A qualified Indian coal facility is a facility placed in service before January 1, 2009, that 

produces coal from reserves that on June 14, 2005, were owned by a Federally recognized tribe 

of Indians or were held in trust by the United States for a tribe or its members. 

The credit is a component of the general business credit,88 allowing excess credits to be 

carried back one year and forward up to 20 years. The credit is also subject to the alternative 

minimum tax. 

 86 Sec. 43. 

87 Secs. 43(b) and 45K(d)(2)(C). 

88 Sec. 38(b)(8). 
72 

3. Marginal wells credit (sec. 45I) 

The Code provides a $3-per-barrel credit (adjusted for inflation) for the production of 

crude oil and a $0.50-per-1,000-cubic-feet credit (also adjusted for inflation) for the production 

of qualified natural gas. In both cases, the credit is available only for domestic production from a 

“qualified marginal well.” 

A qualified marginal well is defined as a domestic well: (1) production from which is 

treated as marginal production for purposes of the Code percentage depletion rules; or (2) that 

during the taxable year had average daily production of not more than 25 barrel equivalents and 

produces water at a rate of not less than 95 percent of total well effluent. The maximum amount 

of production on which credit could be claimed is 1,095 barrels or barrel equivalents. 

The credit is not available to production occurring if the reference price of oil exceeds 

$18 ($2.00 for natural gas). The credit is reduced proportionately as for reference prices between 

$15 and $18 ($1.67 and $2.00 for natural gas). Currently the credit is phased out completely. 

In the case of production from a qualified marginal well which is eligible for the credit 

allowed under section 45K for the taxable year, no marginal well credit is allowable unless the 

taxpayer elects not to claim the credit under section 45K with respect to the well. The section 

45K credit is currently expired with respect to qualified natural gas and oil production. The 

credit is treated as a general business credit. Unused credits can be carried back for up to five 

years rather than the generally applicable carryback period of one year. 

4. Recovery of intangible drilling and development costs (secs. 59, 263, and 291) 

The Code provides special rules for the treatment of intangible drilling and development 

costs (“IDCs”). Under these special rules, an operator or working interest owner89 that pays or 

incurs IDCs in the development of an oil or gas property located in the United States may elect 

either to expense or capitalize those costs.90

IDCs include all expenditures made by an operator for wages, fuel, repairs, hauling, 

supplies, etc., incident to and necessary for the drilling of wells and the preparation of wells for 

the production of oil and gas. In addition, IDCs include the cost to operators of any drilling or 

development work done by contractors under any form of contract, including a turnkey contract. 

Such work includes labor, fuel, repairs, hauling, and supplies which are used (1) in the drilling, 

shooting, and cleaning of wells; (2) in the clearing of ground, draining, road making, surveying, 

and geological works as necessary in preparation for the drilling of wells; and (3) in the 

construction of such derricks, tanks, pipelines, and other physical structures as are necessary for 

 89 An operator or working interest owner is defined as a person that holds a working or operating 

interest in any tract or parcel of land either as a fee owner or under a lease or any other form of contract 

granting working or operating rights. 

90 Sec. 263(c). 
73 

the drilling of wells and the preparation of wells for the production of oil and gas. Generally, 

IDCs do not include expenses for items that have a salvage value (such as pipes and casings) or 

items that are part of the acquisition price of an interest in the property.91 They also do not 

include the cost to operators (1) payable only out of production or gross or net proceeds from 

production, if the amounts are depletable income to the recipient, and (2) amounts properly 

allocable to the cost of depreciable property. 

If an election to expense IDCs is made, the taxpayer deducts the amount of the IDCs as 

an expense in the taxable year the cost is paid or incurred. Generally, if IDCs are not expensed, 

but are capitalized, they may be recovered through depletion or depreciation, as appropriate. In 

the case of a nonproductive well (“dry hole”), IDCs may be deducted at the election of the 

operator.92 For an integrated oil company that has elected to expense IDCs, 30 percent of the 

IDCs on productive wells must be capitalized and amortized over a 60-month period.93

Notwithstanding the fact that a taxpayer has made the election to deduct IDCs, the Code 

provides an additional election under which the taxpayer is allowed to capitalize and amortize 

certain IDCs over a 60-month period beginning with the month the expenditure was paid or 

incurred.94 This election applies on an expenditure-by-expenditure basis; that is, for any 

particular taxable year, a taxpayer may deduct some portion of its IDCs and capitalize the rest 

under this provision. The election allows a taxpayer to reduce or eliminate the IDC adjustments 

or preferences under the alternative minimum tax. 

The election to deduct IDCs applies only to those IDCs associated with domestic 

properties.95 For this purpose, the United States includes certain wells drilled offshore.96

 91 Treas. Reg. sec. 1.612-4(a). 

92 Treas. Reg. sec. 1.612-4(b)(4). 

93 Sec. 291(b)(1)(A). The IRS has ruled that, if a company that has capitalized and begun to 

amortize IDCs over a 60-month period pursuant to section 291 ceases to be an integrated oil company, it 

may not immediately write off the unamortized portion of the capitalized IDCs, but instead must continue 

to amortize the IDCs so capitalized over the 60-month amortization period. Rev. Rul. 93-26, 1993-1 C.B. 

50. 

94 Sec. 59(e)(1). 

95 In the case of IDCs paid or incurred with respect to an oil or gas well located outside of the 

United States, the costs, at the election of the taxpayer, are either (1) included in adjusted basis for 

purposes of computing the amount of any deduction allowable for cost depletion or (2) capitalized and 

amortized ratably over a 10-year period beginning with the taxable year such costs were paid or incurred 

(sec. 263(i)). 

96 The term “United States” for this purpose includes the seabed and subsoil of those submarine 

areas that are adjacent to the territorial waters of the United States and over which the United States has 

exclusive rights, in accordance with international law, with respect to the exploration and exploitation of 

natural resources (i.e., the Continental Shelf area) (sec. 638). 
74 

Pursuant to a special exception, the uniform capitalization rules do not apply to IDCs 

incurred with respect to oil or gas wells that are otherwise deductible under the Code.97

5. Deduction for qualified tertiary injectants (sec. 193) 

Taxpayers engaged in petroleum extraction activities may generally deduct qualified 

tertiary injectant expenses used while applying a tertiary recovery method, including carbon 

dioxide augmented waterflooding and immiscible carbon dioxide displacement.98 The deduction 

is available even if such costs are otherwise subject to capitalization. The deduction is permitted 

for the later of--(1) the tax year in which the injectant is injected or (2) the tax year in which the 

expenses are paid or incurred.99 No deduction is permitted for expenditures for which a taxpayer 

has elected to deduct such costs under section 263(c) (intangible drilling costs) or if a deduction 

is allowed for such amounts under any other income tax provision.100

A “qualified tertiary injectant expense” is defined as any cost paid or incurred for any 

tertiary injectant (other than a recoverable hydrocarbon injectant) which is used as part of a 

tertiary recovery method.101 The cost of a recoverable hydrocarbon injectant (which includes 

natural gas, crude oil and any other injectant with more than an insignificant amount of natural 

gas or crude oil) is not a qualified tertiary injectant expense unless the amount of the recoverable 

hydrocarbon injectant in the qualified tertiary injectant is insignificant.102

6. Arbitrage exception for prepayments of natural gas (sec. 148) 

Arbitrage restrictions

Interest on bonds issued by States or local governments to finance activities carried out or 

paid for by those entities generally is exempt from income tax. Restrictions are imposed on the 

ability of States or local governments to invest the proceeds of these bonds for profit (the 

“arbitrage restrictions”).103 One such restriction limits the use of bond proceeds to acquire 

“investment-type property.” The term investment-type property includes the acquisition of 

property in a transaction involving a prepayment if a principal purpose of the prepayment is to 

 97 Sec. 263A(c)(3). 

98 Sec. 193. 

99 Treas. Reg. sec. 1.193-1. 

100 Sec. 193(c). 

101 Sec. 193(b). A tertiary recovery method is any of the nine methods described in section 

212.78(c)(1) - (9) of the June 1979 energy regulations, as defined in former section 4996(b)(8)(C), or any 

other method approved by the Internal Revenue Service. 

102 Sec. 193(b)(2). 

103 Sec. 148. 
75 

receive an investment return from the time the prepayment is made until the time payment 

otherwise would be made. A prepayment can produce prohibited arbitrage profits when the 

discount received for prepaying the costs exceeds the yield on the tax-exempt bonds. In general, 

prohibited prepayments include all prepayments that are not customary in an industry by both 

beneficiaries of tax-exempt bonds and other persons using taxable financing for the same 

transaction. 

Arbitrage exceptions for certain prepayments

On August 4, 2003, the Treasury Department issued final regulations deeming to be 

customary, and not in violation of the arbitrage rules, certain prepayments for natural gas and 

electricity.104 Generally, a qualified prepayment under the regulations requires that 90 percent of 

the natural gas or electricity purchased with the prepayment be used for a qualifying use. 

Generally, natural gas is used for a qualifying use if it is to be (1) furnished to retail gas 

customers of the issuing municipal utility who are located in the natural gas service area of the 

issuing municipal utility, however, gas used to produce electricity for sale is not included under 

this provision; (2) used by the issuing municipal utility to produce electricity that will be 

furnished to retail electric service area customers of the issuing utility; (3) used by the issuing 

municipal utility to produce electricity that will be sold to a utility owned by a governmental 

person and furnished to the service area retail electric customers of the purchaser; (4) sold to a 

utility that is owned by a governmental person if the requirements of (1), (2) or (3) are satisfied 

by the purchasing utility (treating the purchaser as the issuing utility); or (5) used to fuel the 

pipeline transportation of the prepaid gas supply. Electricity is used for a qualifying use if it is to 

be (1) furnished to retail service area electric customers of the issuing municipal utility or 

(2) sold to a municipal utility and furnished to retail electric customers of the purchaser who are 

located in the electricity service area of the purchaser. 

The Energy Policy Act of 2005 (the “Act”) created a statutory exception to the general 

rule that tax-exempt bond-financed prepayments violate the arbitrage restrictions. Under the 

Act, the term “investment type property” does not include a prepayment under a qualified natural 

gas supply contract. 

 A contract is a qualified natural gas contract if the volume of natural gas secured for any 

year covered by the prepayment does not exceed the sum of (1) the average annual natural gas 

purchased (other than for resale) by customers of the utility within the service area of the utility 

(“retail natural gas consumption”) during the testing period, and (2) the amount of natural gas 

that is needed to fuel transportation of the natural gas to the governmental utility. The testing 

period is the 5-calendar-year period immediately preceding the calendar year in which the bonds 

are issued. A retail customer is one who does not purchase natural gas for resale. Natural gas 

used to generate electricity by a utility owned by a governmental unit is counted as retail natural 

gas consumption if the electricity was sold to retail customers within the service area of the 

governmental electric utility. 

 104 Treas. Reg. sec. 1.148-1(e)(2)(iii). 
76 

Adjustments

The volume of gas permitted by the general rule is reduced by natural gas otherwise 

available on the date of issuance. Specifically, the amount of natural gas permitted to be 

acquired under a qualified natural gas contract for any period is to be reduced by the applicable 

share of natural gas held by the utility on the date of issuance of the bonds and natural gas that 

the utility has a right to acquire for the prepayment period (determined as of the date of 

issuance). For purposes of the preceding sentence, “applicable share” means, with respect to any 

period, the natural gas allocable to such period if the gas were allocated ratably over the period to 

which the prepayment relates. 

For purposes of the safe harbor, if after the close of the testing period and before the issue 

date of the bonds (1) the government utility enters into a contract to supply natural gas (other 

than for resale) for a commercial person for use at a property within the service area of such 

utility and (2) the gas consumption for such property was not included in the testing period or the 

ratable amount of natural gas to be supplied under the contract is significantly greater than the 

ratable amount of gas supplied to such property during the testing period, then the amount of gas 

permitted to be purchased may be increased to accommodate the contract. 

The calculation of average annual retail natural gas consumption for purposes of the safe 

harbor, however, is not to exceed the annual amount of natural gas reasonably expected to be 

purchased (other than for resale) by persons who are located within the service area of such 

utility and who, as of the date of issuance of the issue, are customers of such utility. 

Intentional acts

The safe harbor does not apply if the utility engages in intentional acts to render (1) the 

volume of natural gas covered by the prepayment to be in excess of that needed for retail natural 

gas consumption, and (2) the amount of natural gas that is needed to fuel transportation of the 

natural gas to the governmental utility. 

Definition of service area

Service area is defined as (1) any area throughout which the governmental utility 

provided (at all times during the testing period) in the case of a natural gas utility, natural gas 

transmission or distribution services, or in the case of an electric utility, electricity distribution 

services; (2) limited areas contiguous to such areas; and (3) any area recognized as the service 

area of the governmental utility under State or Federal law. Contiguous areas are limited to any 

area within a county contiguous to the area described in item (1) above in which retail customers 

of the utility are located if such area is not also served by another utility providing the same 

service. 

Ruling request for higher prepayment amounts

Upon written request, the Secretary may allow an issuer to prepay for an amount of gas 

greater than that allowed by the safe harbor based on objective evidence of growth in gas 

consumption or population that demonstrates that the amount permitted by the exception is 

insufficient. 
77 

Application to joint action agencies

In a number of States, joint action agencies serve as purchasing agents for their member 

municipal gas utilities. The provision is intended to allow municipal utilities in a State to 

participate in such buying arrangements as established under State law, subject to the same 

limitations that would apply if an individual utility were to purchase gas directly. When acting 

on behalf of its municipal gas utility members, the total amount of gas that can be purchased by a 

joint action agency under the provision’s exception to the arbitrage rules is the aggregate of what 

each such member could purchase for itself on a direct basis. Thus, with respect to qualified 

natural gas supply contracts entered into by joint action agencies for or on behalf of one or more 

member municipal utilities, the requirements of the safe harbor are tested at the individual 

municipal utility level based on the amount of gas that would be allocated to such member 

during any year covered by the contract. 

7. Amortization of geological and geophysical expenditures (sec. 167(h)) 

Geological and geophysical expenditures (“G&G costs”) are costs incurred by a taxpayer 

for the purpose of obtaining and accumulating data that will serve as the basis for the acquisition 

and retention of mineral properties by taxpayers exploring for minerals. G&G costs incurred by 

independent producers and smaller integrated oil companies in connection with oil and gas 

exploration in the United States may generally be amortized over two years.105

Major integrated oil companies are required to amortize all G&G costs over seven years 

for costs paid or incurred after December 19, 2007 (the date of enactment of the Energy 

Independence and Security Act of 2007, Pub. L. No. 110-140).106 A major integrated oil 

company, as defined in section 167(h)(5)(B), is an integrated oil company107 which has an 

average daily worldwide production of crude oil of at least 500,000 barrels for the taxable year, 

had gross receipts in excess of one billion dollars for its last taxable year ending during the 

calendar year 2005, and generally has an ownership interest in a crude oil refiner of 15 percent or 

more. 

 105 This amortization rule applies to G&G costs incurred in taxable years beginning after August 

8, 2005, the date of enactment of the Energy Policy Act of 2005, Pub. L. No. 109-58. Prior to the 

effective date, G&G costs associated with productive properties were generally deductible over the life of 

such properties, and G&G costs associated with abandoned properties were generally deductible in the 

year of abandonment. 

106 Prior to the enactment of the Energy Independence and Security Act of 2007, major integrated 

oil companies were required to amortize G&G costs paid or incurred after May 17, 2006 over five years, 

as provided in Energy Tax Incentives Act of 2005. 

107 Generally, an integrated oil company is a producer of crude oil that engages in the refining or 

retail sale of petroleum products in excess of certain threshold amounts. 
78 

In the case of abandoned property, remaining basis may not be recovered in the year of 

abandonment of a property, but instead must continue to be amortized over the remaining 

applicable amortization period. 

8. Passive loss rules for working interests in oil and gas property (sec. 469) 

Present Law

The passive loss rules limit deductions and credits from passive trade or business 

activities.108 Deductions attributable to passive activities, to the extent they exceed income from 

passive activities, generally may not be deducted against other income. Deductions and credits 

that are suspended under these rules are carried forward and treated as deductions and credits 

from passive activities in the next year. The suspended losses from a passive activity are 

allowed in full when a taxpayer disposes of his entire interest in the passive activity to an 

unrelated person. 

Losses from certain working interests in oil and gas property are not limited under the 

passive loss rule. Thus, losses and credits from such interests can be used to offset other income 

of the taxpayer without limitation under the passive loss rule. A passive activity does not include 

a working interest in any oil or gas property that the taxpayer holds directly or through an entity 

that does not limit the liability of the taxpayer with respect to the interest. This rule applies 

without regard to whether the taxpayer materially participates in the activity. If the taxpayer has 

a loss from a working interest in any oil or gas property that is treated as not from a passive 

activity, then net income from the property for any succeeding taxable year is treated as income 

of the taxpayer that is not from a passive activity. 

In general, a working interest is an interest with respect to an oil and gas property that is 

burdened with the cost of development and operation of the property. Rights to overriding 

royalties, production payments, and the like, do not constitute working interests, because they are 

not burdened with the responsibility to share expenses of drilling, completing, or operating oil 

and gas property. Similarly, contract rights to extract or share in oil and gas, or in profits from 

extraction, without liability to share in the costs of production, do not constitute working 

interests. Income from such interests generally is considered to be portfolio income. 

A working interest generally has characteristics such as responsibility for signing 

authorizations for expenditures with respect to the activity, receiving periodic drilling and 

completion reports, receiving periodic reports regarding the amount of oil extracted, possession 

of voting rights proportionate to the percentage of the working interest possessed by the 

taxpayer, the right to continue activities if the present operator decides to discontinue operations, 

a proportionate share of tort liability with respect to the property (e.g., if a well catches fire), and 

some responsibility to share in further costs with respect to the property in the event that a 

decision is made to spend more than amounts already contributed. 

 108 Sec. 469. 
79 

However, the fact that a taxpayer is entitled to decline, or does decline, to make 

additional contributions under a buyout, nonparticipation, or similar arrangement, does not 

prevent such taxpayer’s possessing a working interest. In addition, the fact that tort liability may 

be insured against does not prevent such taxpayer’s possessing a working interest. 

When the taxpayer’s form of ownership limits the liability of the taxpayer, the interest 

possessed by such taxpayer is not a working interest for purposes of the passive loss provision. 

Thus, for purposes of the passive loss rules, an interest owned by a limited partnership is not 

treated as a working interest with regard to any limited partner, and an interest owned by an S 

corporation is not treated as a working interest with regard to any shareholder. The same result 

follows with respect to any form of ownership that is substantially equivalent in its effect on 

liability to a limited partnership interest or interest in an S corporation, even if different in form. 

When an interest is not treated as a working interest because the taxpayer’s form of 

ownership limits his liability, the general rules regarding material participation apply to 

determine whether the interest is treated as in a passive activity. Thus, for example, a limited 

partner’s interest generally is treated as in a passive activity. In the case of a shareholder in an S 

corporation, the general facts and circumstances test for material participation applies and the 

working interest exception does not apply, because the form of ownership limits the taxpayer's 

liability. 

In determining whether the taxpayer’s form of ownership limits his liability, the rule 

described in the two prior paragraphs is applied by looking through tiered entities. For example, 

a general partner in a partnership that owns a limited partnership interest in a partnership that 

owns a working interest is not treated as owning a working interest. 

A special rule applies in any case where, for a prior taxable year, net losses from a 

working interest in a property were treated by the taxpayer as not from a passive activity. In such 

a case, any net income realized by the taxpayer from the property (or from any substituted basis 

property, e.g., property acquired in a sec. 1031 like kind exchange for such property) in a 

subsequent year also is treated as active. Under this rule, for example, if a taxpayer claims losses 

for a year with regard to a working interest and then, after the property to which the interest 

relates begins to generate net income, transfers the interest to an S corporation in which he is a 

shareholder, or to a partnership in which he has an interest as a limited partner, his interest with 

regard to the property continues to be treated as not passive. 

9. Depletion (secs. 611-613A) 

In general

Depletion, like depreciation, is a form of capital cost recovery. In both cases, the 

taxpayer is allowed a deduction in recognition of the fact that an asset is being expended in order 

to produce income.109 Certain costs incurred prior to drilling an oil or gas property or extracting 

 109 In the context of mineral extraction, depreciable assets are generally used to recover 

depletable assets. For example, natural gas gathering lines, used to collect and deliver natural gas, have a 

class life of 14 years and a depreciation recovery period of seven years. 
80 

minerals are recovered through the depletion deduction. These include the cost of acquiring the 

lease or other interest in the property. 

Depletion is available to any person having an economic interest in a producing property. 

An economic interest is possessed in every case in which the taxpayer has acquired by 

investment any interest in minerals in place, and secures, by any form of legal relationship, 

income derived from the extraction of the mineral, to which it must look for a return of its 

capital. Thus, for example, both working interests and royalty interests in an oil- or gasproducing property constitute economic interests, thereby qualifying the interest holders for 

depletion deductions with respect to the property. A taxpayer who has no capital investment in 

the mineral deposit, however, does not acquire an economic interest merely by possessing an 

economic or pecuniary advantage derived from production through a contractual relation. 

Two methods of depletion are currently allowable under the Code: (1) the cost depletion 

method, and (2) the percentage depletion method.110 Under the cost depletion method, the 

taxpayer deducts that portion of the adjusted basis of the depletable property which is equal to 

the ratio of units sold from that property during the taxable year to the number of units remaining 

as of the end of taxable year plus the number of units sold during the taxable year. Thus, the 

amount recovered under cost depletion may never exceed the taxpayer’s basis in the property. 

Under the percentage depletion method, a percentage, varying from five percent to 22 

percent (generally 15 percent for oil and gas properties), of the taxpayer’s gross income from a 

producing property is allowed as a deduction in each taxable year.111 The amount deducted 

generally may not exceed 50 percent (100 percent in the case of oil and gas properties) of the net 

income from the oil and gas property in any year (the “net-income limitation”).112 Additionally, 

the percentage depletion deduction for all oil and gas properties may not exceed 65 percent of the 

taxpayer’s overall taxable income for the year (determined before such deduction and adjusted 

for certain loss carrybacks and trust distributions).113 

The percentage depletion rate for coal and lignite is 10 percent.114 The percentage 

depletion rate for oil shale is 15 percent.115 In the case of iron ore and coal (including lignite), a 

corporate preference reduces the amount of percentage depletion calculated by 20 percent of the 

 110 Secs. 611 - 613. 

111 Sec. 613A(c). The Code generally limits the percentage depletion method for oil and gas 

properties to independent producers and royalty owners. 

112 Sec. 613(a). For marginal production, discussed infra, this limitation is suspended for taxable 

years beginning after December 31, 1997, and before January 1, 2008, and for taxable years beginning 

after December 31, 2008 and before January 1, 2010.

113 Sec. 613A(d)(1). 

114 Sec. 613(b)(4). 

115 Sec. 613(b)(1)(2)(B). 
81 

amount of percentage depletion in excess of the adjusted basis of the property at the close of the 

taxable year (determined without regard to the depletion deduction for the taxable year).116 

Because percentage depletion, unlike cost depletion, is computed without regard to the 

taxpayer’s basis in the depletable property, cumulative depletion deductions may be greater than 

the amount expended by the taxpayer to acquire or develop the property. A taxpayer is required 

to determine the depletion deduction for each property under both the percentage depletion 

method (if the taxpayer is entitled to use this method) and the cost depletion method. If the cost 

depletion deduction is larger, the taxpayer must utilize that method for the taxable year in 

question.117

Limitation on oil and gas percentage depletion to independent producers and royalty 

owners

As stated above, percentage depletion of oil and gas properties generally is not permitted, 

except for independent producers and royalty owners, certain fixed-price gas contracts, and 

natural gas from geopressured brine. For purposes of the percentage depletion allowance, an 

independent producer is any producer that is not a “retailer” or “refiner.” A retailer is any person 

that directly, or through a related person, sells oil or natural gas (or a derivative thereof): 

(1) through any retail outlet operated by the taxpayer or related person, or 

(2) to any person that is obligated to market or distribute such oil or natural gas (or a 

derivative thereof) under the name of the taxpayer or the related person, or that has the authority 

to occupy any retail outlet owned by the taxpayer or a related person.118 

Bulk sales of crude oil and natural gas to commercial or industrial users, and bulk sales of 

aviation fuel to the Department of Defense, are not treated as retail sales. Further, if the 

combined gross receipts of the taxpayer and all related persons from the retail sale of oil, natural 

gas, or any product derived therefrom do not exceed $5 million for the taxable year, the taxpayer 

will not be treated as a retailer. 

A refiner is any person that directly or through a related person engages in the refining of 

crude oil in excess of an average daily refinery run of 75,000 barrels during the taxable year.119

Percentage depletion for eligible taxpayers is allowed for up to 1,000 barrels of average 

daily production of domestic crude oil or an equivalent amount of domestic natural gas.120 For 

 116 Sec. 291(a)(2). 

117 Sec. 613(a). 

118 Sec. 613A(d)(2). 

119 Sec. 613A(d)(4). 

120 Sec. 613A(c). 
82 

producers of both oil and natural gas, this limitation applies on a combined basis. All production 

owned by businesses under common control and members of the same family must be 

aggregated;121 each group is then treated as one producer in applying the 1,000-barrel limitation. 

In addition to independent producers and royalty owners, certain sales of natural gas 

under a fixed contract in effect on February 1, 1975, and certain natural gas from geopressured 

brine, are eligible for percentage depletion, at rates of 22 percent and 10 percent, respectively. 

These exceptions apply without regard to the 1,000-barrel-per-day limitation and regardless of 

whether the producer is an independent producer or an integrated oil company. 

Before enactment of the Omnibus Budget Reconciliation Act of 1990 (the “1990 Act”), if 

an interest in a proven oil or gas property was transferred (subject to certain exceptions), the 

production from such interest did not qualify for percentage depletion. The 1990 Act repealed 

the limitation on claiming percentage depletion on transferred properties effective for property 

transfers occurring after October 11, 1990. 

Percentage depletion on marginal production

The 1990 Act also created a special percentage depletion provision for oil and gas 

production from so-called marginal properties held by independent producers or royalty 

owners.122 Under this provision, the statutory percentage depletion rate is increased (from the 

general rate of 15 percent) by one percent for each whole dollar that the average price of crude 

oil for the immediately preceding calendar year is less than $20 per barrel. In no event may the 

rate of percentage depletion under this provision exceed 25 percent for any taxable year. The 

increased rate applies for the taxpayer’s taxable year that immediately follows a calendar year for 

which the average crude oil price falls below the $20 floor. To illustrate the application of this 

provision, the average price of a barrel of crude oil for calendar year 1999 was $15.56. Thus, the 

percentage depletion rate for production from marginal wells was increased to 19 percent for 

taxable years beginning in 2000. Since the price of oil currently is above the $20 floor, there is 

no increase in the statutory depletion rate for marginal production. 

The Code defines the term “marginal production” for this purpose as domestic crude oil 

or domestic natural gas which is produced during any taxable year from a property which (1) is a 

stripper well property for the calendar year in which the taxable year begins, or (2) is a property 

substantially all of the production from which during such calendar year is heavy oil (i.e., oil that 

has a weighted average gravity of 20 degrees API or less, corrected to 60 degrees Fahrenheit).123 

A stripper well property is any oil or gas property that produces a daily average of 15 or fewer 

 121 Sec. 613A(c)(8). 

122 Sec. 613A(c)(6). 

123 Sec. 613A(c)(6)(D). 
83 

equivalent barrels of oil and gas per producing oil or gas well on such property in the calendar 

year during which the taxpayer’s taxable year begins.124 

The determination of whether a property qualifies as a stripper well property is made 

separately for each calendar year. The fact that a property is or is not a stripper well property for 

one year does not affect the determination of the status of that property for a subsequent year. 

Further, a taxpayer makes the stripper well property determination for each separate property 

interest (as defined under section 614) held by the taxpayer during a calendar year. The 

determination is based on the total amount of production from all producing wells that are treated 

as part of the same property interest of the taxpayer. A property qualifies as a stripper well 

property for a calendar year only if the wells on such property were producing during that period 

at their maximum efficient rate of flow. 

If a taxpayer’s property consists of a partial interest in one or more oil- or gas-producing 

wells, the determination of whether the property is a stripper well property or a heavy oil 

property is made with respect to total production from such wells, including the portion of total 

production attributable to ownership interests other than the taxpayer’s interest. If the property 

satisfies the requirements of a stripper well property, then the benefits of this provision apply 

with respect to the taxpayer’s allocable share of the production from the property. The deduction 

is allowed for the taxable year that begins during the calendar year in which the property so 

qualifies. 

The allowance for percentage depletion on production from marginal oil and gas 

properties is subject to the 1,000-barrel-per-day limitation discussed above. Unless a taxpayer 

elects otherwise, marginal production is given priority over other production for purposes of 

utilization of that limitation.

 124 Sec. 613A(c)(6)(E). 
84 

D. Provisions Relating to Refining 

1. Tax incentives for refining (secs. 45H, 168, 179B, and 179C) 

General rule for depreciating refinery assets (sec. 168)

A taxpayer is allowed to recover, through annual depreciation deductions, the cost of 

certain property used in a trade or business or for the production of income. The amount of the 

depreciation deduction allowed with respect to tangible property for a taxable year is determined 

under the modified accelerated cost recovery system (“MACRS”). The applicable recovery 

period for assets placed in service under the MACRS is based on the “class life of the property.” 

Except where provided specifically by statute, the class lives of assets placed in service after 

1986 are generally set forth in Revenue Procedure 87-56.125 In the Revenue Procedure, 

petroleum refining assets are assigned a 10-year recovery period and a class life of 16 years. 

Petroleum refining assets are assets used for distillation, fractionation, and catalytic cracking of 

crude petroleum into gasoline and its other components. 

Temporary election to expense 50 percent of qualified property used in refining liquid fuels 

(sec. 179C)

Taxpayers may elect to expense 50 percent of the cost of any qualified property used for 

processing liquid fuel from crude oil or qualified fuels (as defined in section 45K(c)126 of the 

Code). The remaining 50 percent is recovered under the otherwise applicable rules. Qualified 

refinery property includes assets located in the United States that are used in the refining of 

liquid fuels: (1) with respect to the construction of which a binding construction contract has 

been entered into before January 1, 2010;127 (2) which are placed in service before January 1, 

2014; (3) which increase the capacity of an existing refinery by at least five percent or increase 

the percentage of total throughput attributable to qualified fuels such that it equals or exceeds 25 

percent; and (4) which meet all applicable environmental laws in effect when the property is 

placed in service. 

Special expensing rule for capital costs incurred by small refiners to comply with EPA 

sulfur regulations (sec. 179B)

 Under present law, a small business refiner may immediately deduct as an expense 75 

percent of the costs paid or incurred for purposes of complying with the Highway Diesel Fuel 

 125 1987-2 C.B. 674 (as clarified and modified by Rev. Proc. 88-22, 1988-1 C.B. 785). 

126 Under Code section 45K(c), qualified fuels are (1) oil produced from shale and tar sands; (2) 

gas produced from geopressured brine, Devonian shale, coal seams, or a tight formation, or biomass; and 

(3) liquid, gaseous, or solid synthetic fuels produced from coal (including lignite). 

127 This requirement also may be met by placing the property in service before January 1, 2010 

or, in the case of self-constructed property, by beginning construction after June 14, 2005 and before 

January 1, 2008. 
85 

Sulfur Control requirement of the Environmental Protection Agency (“EPA”). A cooperative 

that qualifies as a small business refiner may elect to pass this deduction through to its owners. 

Costs qualifying for the deduction are those costs paid or incurred with respect to any 

facility of a small business refiner during the period beginning on January 1, 2003 and ending on 

the earlier of the date that is one year after the date on which the taxpayer must comply with the 

applicable EPA regulations or December 31, 2009. A small business refiner is a crude oil refiner 

that has no more than 1,500 individuals engaged in refinery operations on any given day and that 

had an average daily domestic refinery run or average retained production of not more than 

205,000 barrels for the one-year period ending on December 31, 2002. 

Credit for small refiners for production of diesel fuel in compliance with EPA sulfur 

regulations (sec. 45H)

Under present law, a small business refiner (as defined above) may claim a credit of five 

cents per gallon for each gallon of low sulfur diesel fuel produced during the taxable year that is 

in compliance with the Highway Diesel Fuel Sulfur Control Requirements of the EPA. 

The total production credit claimed by the taxpayer is limited to 25 percent of the capital 

costs incurred to come into compliance with the EPA diesel fuel requirements. The percentage 

limitation phases down pro rata for refiners that had runs in 2002 exceeding 155,000 barrels but 

less than 205,000 barrels. 

Costs qualifying for the credit are those costs paid or incurred with respect to any facility 

of a small business refiner during the period beginning on January 1, 2003 and ending on the 

earlier of the date that is one year after the date on which the taxpayer must comply with the 

applicable EPA regulations or December 31, 2009. The taxpayer’s basis in property with respect 

to which the credit applies is reduced by the amount of the production credit claimed. 

2. Credit for producing coke or coke gas (sec. 45K) 

Coke and coke gas produced in the United States at qualified facilities and sold to 

unrelated parties are eligible for an income tax credit equal to $3 (generally adjusted for 

inflation)128 per Btu oil barrel equivalent (the “coke credit”). The credit is available for coke or 

coke gas produced during a four-year period beginning on the later of January 1, 2006, or the 

date the qualified facility was placed in service. For purposes of the coke credit, qualified 

facilities are facilities placed in service before January 1, 1993, or after June 30, 1998, and before 

January 1, 2010. Qualified facilities do not include facilities that produce petroleum-based coke 

or coke gas. The amount of credit-eligible coke produced at any one facility may not exceed an 

average barrel-of-oil equivalent of 4,000 barrels per day. The coke credit is part of the general 

business credit. 

 128 The inflation adjustment is calculated using 2004 as the base year. 
86 

E. Provisions Relating to Energy Transportation or Transmission 

1. Cost recovery of certain energy transportation and transmission property 

(sec. 168(e)(3)) 

In general

A taxpayer is allowed to recover, through annual depreciation deductions, the cost of 

certain property used in a trade or business or for the production of income. The amount of the 

depreciation deduction allowed with respect to tangible property for a taxable year is determined 

under the modified accelerated cost recovery system (“MACRS”). Under MACRS, different 

types of property are generally assigned applicable recovery periods and depreciation methods. 

The recovery periods applicable to most tangible personal property (generally tangible property 

other than residential rental property and nonresidential real property) range from three to 25 

years. The depreciation methods generally applicable to tangible personal property are the 200-

percent and 150-percent declining balance methods, switching to the straight-line method for the 

taxable year in which the depreciation deduction would be maximized.129 In general, the 

recovery periods applicable to real property are 39 years for non-residential real property and 

27.5 years for residential rental property. The depreciation method for real property is the 

straight-line method. 

Under MACRS, the full basis of depreciable property is recovered by the taxpayer over 

the applicable recovery period; there is no need to estimate salvage value. Furthermore, under 

MACRS, the applicable recovery period need not (and typically does not) correspond to the 

actual economic life of the asset subject to depreciation. In general, however, MACRS generally 

provides for longer recovery periods for longer lived assets. 

Alaska natural gas pipeline (sec. 168(e)(3)(C)(iii))

The Code provides a statutory seven year recovery period and a class life of 22 years for 

any Alaska natural gas pipeline. The term “Alaska natural gas pipeline” is defined as any natural 

gas pipeline system (including the pipe, trunk lines, related equipment, and appurtenances used 

to carry natural gas, but not any gas processing plant) located in the State of Alaska that has a 

capacity of more than 500 billion Btu of natural gas per day and is placed in service after 

December 31, 2013.130 A taxpayer who places an otherwise qualifying system in service before 

January 1, 2014 may elect to treat the system as placed in service on January 1, 2014, thus 

qualifying for the seven-year recovery period. Absent such an election, the system is subject to 

the prior law recovery period of 15 years. 

 129 For certain property, including tangible property used predominantly outside the United 

States, tax-exempt use property, tax-exempt bond-financed property, and certain other property, the 

MACRS “alternative depreciation system” of section 168(g) applies, generally increasing recovery 

periods and requiring straight-line depreciation. 

130 Sec. 168(i)(16). 
87 

Natural gas distribution lines (sec. 168(e)(3)(E)(viii))

The Code provides a statutory 15-year recovery period and a class life of 35 years for 

natural gas distribution lines. This provision is effective for property, the original use of which 

begins with the taxpayer after April 11, 2005, and which is placed in service after April 11, 2005 

and before January 1, 2011. The provision does not apply to property subject to a binding 

contract on or before April 11, 2005.131

Natural gas gathering lines (sec. 168(e)(3)(C)(iv))

The Code provides a statutory seven-year recovery period and a class life of 14 years for 

natural gas gathering lines. In addition, no adjustment will be made to the allowable amount of 

depreciation with respect to this property for purposes of computing a taxpayer’s alternative 

minimum taxable income. A natural gas gathering line is defined to include any pipe, 

equipment, and appurtenance that is (1) determined to be a gathering line by the Federal Energy 

Regulatory Commission, or (2) used to deliver natural gas from the wellhead or a common point 

to the point at which such gas first reaches (a) a gas processing plant, (b) an interconnection with 

an interstate transmission line, (c) an interconnection with an intrastate transmission line, or (d) a 

direct interconnection with a local distribution company, a gas storage facility, or an industrial 

consumer.132

Electricity Transmission Property (sec. 168(e)(3)(E)(vii))

Generally, assets used in the transmission and distribution of electricity for sale and 

related land improvements are assigned a 20-year recovery period and a class life of 30 years. 

However, the Code provides a statutory 15-year recovery period and a class life of 30 years for 

certain assets used in the transmission of electricity for sale and related land improvements. 

Such assets include section 1245 property133 used in the transmission at 69 or more kilovolts of 

electricity for sale, the original use of which commences with the taxpayer after April 11, 2005. 

 131 In the case of self-constructed property, the provision does not apply to property under 

construction on or before April 11, 2005. 

132 Sec. 168(i)(17). 

133 Generally, sec. 1245 property includes personal property. For a complete definition, see sec. 

1245(a)(3). 
88 

2. Five-Year carryback of net operating losses for certain electric utility companies 

(sec. 172(b)(1)(I)) 

In general

A net operating loss (“NOL”) is, generally, the amount by which a taxpayer’s allowable 

deductions exceed the taxpayer’s gross income. A carryback of an NOL generally results in the 

refund of Federal income tax for the carryback year. A carryover of an NOL reduces Federal 

income tax for the carryover year. In general, an NOL may be carried back two years and 

carried over 20 years to offset taxable income in such years.134 Under present-law ordering 

rules, NOLs generally are first applied to the earliest of the taxable years to which the loss may 

be carried. 

Certain electric utility company NOLs

The Code provides an election for certain electric utility companies to extend the 

carryback period to five years for a portion of NOLs arising in 2003, 2004, and 2005 (“loss 

years”). The election may be made during any taxable year ending after December 31, 2005, and 

before January 1, 2009 (“election years”). An electing taxpayer must specify to which loss year 

the election applies. 

The portion of the loss year NOL to which the election may apply is limited to 20 percent 

of the amount of the taxpayer’s qualifying investment in the taxable year prior to the year in 

which the election is made (the “qualifying investment limitation”), with any remaining portion 

of the loss year NOL subject to the general NOL carryover rules. Only one election may be 

made in any election year, and elections may not be made for more than one election year 

beginning in the same calendar year. Thus, for example, a taxpayer with two short taxable years 

beginning in calendar year 2006 is eligible to make an election under this provision in only one 

of those two short taxable years. Once an election has been made with respect to a loss year, no 

subsequent election is available with respect to that loss year. 

For purposes of calculating interest on overpayments, any overpayment resulting from a 

five-year NOL carryback elected under this provision is deemed not to have been made prior to 

the filing date for the taxable year in which the election is made. The statute of limitations for 

refund claims, and that for assessment of deficiencies, are also extended. 

An election under this provision is made in such manner as the Secretary may prescribe. 

However, Congress expects that the filing of a refund claim will be considered sufficient for 

 134 Different rules apply with respect to NOLs arising in certain circumstances. For example, a 

three-year carryback applies with respect to NOLs (1) arising from casualty or theft losses of individuals, 

or (2) attributable to Presidentially declared disasters for taxpayers engaged in a farming business or a 

small business. A five-year carryback period applies to NOLs from a farming loss (regardless of whether 

the loss was incurred in a Presidentially declared disaster area). Special rules also apply to real estate 

investment trusts (no carryback), specified liability losses (10-year carryback), and excess interest losses 

(no carryback to any year preceding a corporate equity reduction transaction). 
89 

making the election, provided that the taxpayer attaches to the refund claim a statement 

specifying the election year, the loss year, and the amount of qualifying investment in electric 

transmission property and pollution control facilities in the preceding taxable year. 

Under the provision, an investment in electric transmission property qualifies if it is a 

capital expenditure made by the taxpayer which is attributable to electric transmission property 

used by the taxpayer in the transmission at 69 or more kilovolts of electricity for sale. An 

investment in pollution control equipment qualifies if it is a capital expenditure, made by an 

electric utility company (as defined in the Public Utility Holding Company Act as in effect on 

the day before the date of enactment of the provision), which is attributable to a facility which 

will qualify as a certified pollution control facility, generally as defined under section 169(d)(1) 

but without regard to the requirements therein that the facility be new or that it be used in 

connection with a plant or other property in operation before January 1, 1976. 

There is no requirement that the transmission property or pollution control facilities be 

placed in service in the year in which the capital expenditures are incurred. However, it is 

intended that qualifying investment under the provision includes only capital expenditures to 

which the taxpayer is committed and with respect to property which the taxpayer intends to 

ultimately place in service in the taxpayer’s trade or business. Under the provision, capital 

expenditures which, at the taxpayer’s option, are refundable or subject to material modification 

in a manner which would not meet the requirements of the provision, may not be taken into 

account. For example, if a taxpayer makes a cash deposit with respect to a contract for the 

purchase of electric transmission property, and the contract contains an option (or there is 

otherwise an understanding) under which the taxpayer may subsequently apply the deposit to the 

purchase of equipment other than electric transmission property, the deposit is not included in 

the taxpayer’s qualifying investment. This rule is intended as an anti-abuse rule and should be 

interpreted to prevent a taxpayer from taking into account capital expenditures to which the 

taxpayer is not permanently committed. 

3. Deferral of gains from the sale of electric transmission property (sec. 451(i)) 

Generally, a taxpayer recognizes gain to the extent the sales price (and any other 

consideration received) exceeds the seller’s basis in the property. The recognized gain is subject 

to current income tax unless the gain is deferred or not recognized under a special tax provision. 

With regard to the disposition of certain electric transmission property, taxpayers may elect to 

recognize gain from qualified electric transmission transactions ratably over an eight-year period 

if the amount realized from such sale is used to purchase exempt utility property within four 

years after the close of the taxable year in which the transaction takes place.135 If the amount 

realized exceeds the amount used to purchase reinvestment property, any realized gain shall be 

recognized to the extent of such excess in the year of the qualifying electric transmission 

transaction, with any remaining realized gain recognized ratably over the eight-year period. 

 135 Sec. 451(i). 
90 

A qualifying electric transmission transaction is the sale or other disposition of property 

used by the taxpayer in the trade or business of providing electric transmission services, or an 

ownership interest in such an entity, to an independent transmission company prior to January 1, 

2010. In general, an independent transmission company is defined as: (1) an independent 

transmission provider136 approved by the Federal Energy Regulatory Commission (“FERC”); (2) 

a person (i) who the FERC determines under section 203 of the Federal Power Act (or by 

declaratory order) is not a “market participant” and (ii) whose transmission facilities are placed 

under the operational control of a FERC-approved independent transmission provider before the 

close of the period specified in such authorization, but not later than December 31, 2007; or (3) 

in the case of facilities subject to the jurisdiction of the Public Utility Commission of Texas, (i) a 

person which is approved by that Commission as consistent with Texas State law regarding an 

independent transmission organization, or (ii) a political subdivision, or affiliate thereof, whose 

transmission facilities are under the operational control of an organization described in (i). 

Exempt utility property is defined as: (1) property used in the trade or business of 

generating, transmitting, distributing, or selling electricity or producing, transmitting, 

distributing, or selling natural gas, or (2) stock in a controlled corporation whose principal trade 

or business consists of the activities described in (1). 

If the taxpayer is a member of an affiliated group of corporations filing a consolidated 

return, the reinvestment property may be purchased by any member of the affiliated group (in 

lieu of the taxpayer). 

 136 For example, a regional transmission organization, an independent system operator, or an 

independent transmission company. 
91 

F. Provisions Relating to Coal and Nuclear Energy 

1. Credit for the production of refined coal (sec. 45) 

In general

A credit is available for refined coal. In general, refined coal is a fuel produced from coal 

that is (1) used to produce steam or (2) used to produce steel industry fuel. 

Refined coal used to produce steam 

An income tax credit is allowed for the production at qualified facilities of certain refined 

coal sold to an unrelated person. The amount of the refined coal credit is $4.375 per ton 

(indexed for inflation after 1992 and equaling $6.061 per ton for 2008). A taxpayer may 

generally claim the credit during the 10-year period commencing with the date the qualified 

facility is placed in service. 

A qualifying refined coal facility is a facility producing refined coal that is placed in 

service after October 22, 2004, and before January 1, 2010. Refined coal is a qualifying liquid, 

gaseous, or solid synthetic fuel produced from coal (including lignite) or high-carbon fly ash, 

including such fuel used as a feedstock. A qualifying fuel is a fuel that, when burned, emits 20 

percent less nitrogen oxides and either sulfur dioxide or mercury than the burning of feedstock 

coal or comparable coal predominantly available in the marketplace as of January 1, 2003, but 

only if the fuel sells at prices at least 50 percent greater than the prices of the feedstock coal or 

comparable coal. In addition, to be qualified refined coal, the taxpayer must sell the fuel with the 

reasonable expectation that it will be used for the primary purpose of producing steam. 

The refined coal credit is reduced over an $8.75 phase-out range as the reference price of 

the fuel used as feedstock for the refined coal exceeds an amount equal to 1.7 times the reference 

price for such fuel in 2002 (adjusted for inflation). The amount of the credit a taxpayer may 

claim is reduced by reason of grants, tax-exempt bonds, subsidized energy financing, and other 

credits, but the reduction cannot exceed 50 percent of the otherwise allowable credit. 

The credit is a component of the general business credit,137 allowing excess credits to be 

carried back one year and forward up to 20 years. The credit is also subject to the alternative 

minimum tax. 

Refined coal facilities used to produce steam that are placed in service after 2008

For refined coal facilities placed in service after 2008, the requirement that the qualified 

refined coal fuel sell at a price at least 50 percent greater than the price of the feedstock coal does 

not apply. However, to be credit-eligible, refined coal produced by such facilities must reduce 

by 40 percent (not 20 percent) the amount by which refined coal must reduce, when burned, 

 137 Sec. 38(b)(8). 
92 

emissions of either sulfur dioxide or mercury compared to the emissions released by the 

feedstock coal or comparable coal predominantly available in the marketplace as of January 1, 

2003. 

Refined coal that is steel industry fuel

Each barrel-of-oil equivalent (defined as 5.8 million British thermal units) of steel 

industry fuel produced at a qualified facility during the credit period receives a $2 credit 

(adjusted for inflation using 1992 as the base year and equal to $2.77 for 2008). A qualified 

facility is any facility capable of producing steel industry fuel (or any modification to a facility 

making it so capable) that is placed in service before January 1, 2010. For facilities capable of 

producing steel industry fuel on or before October 1, 2008, the credit is available for fuel 

produced and sold on or after such date and before January 1, 2010. For facilities placed in 

service or modified to produce steel industry fuel after October 1, 2008, the credit period begins 

on the placed-in-service or modification date and ends one year after such date or December 31, 

2009, whichever is later. 

Steel industry fuel is defined as a fuel produced through a process of liquefying coal 

waste sludge, distributing the liquefied product on coal, and using the resulting mixture as a 

feedstock for the manufacture of coke. Coal waste sludge includes tar decanter sludge and 

related byproducts of the coking process. 

2. Advanced nuclear power production credit (sec. 45J) 

Taxpayers producing electricity at a qualifying advanced nuclear power facility may 

claim a credit equal to 1.8 cents per kilowatt-hour of electricity produced for the eight-year 

period starting when the facility is placed in service.138 The aggregate amount of credit that a 

taxpayer may claim in any year during the eight-year period is subject to limitation based on 

allocated capacity and an annual limitation as described below. 

A qualifying advanced nuclear facility is an advanced nuclear facility for which the 

taxpayer has received an allocation of megawatt capacity from the Secretary and is placed in 

service before January 1, 2021. The taxpayer may only claim credit for production of electricity 

equal to the ratio of the allocated capacity that the taxpayer receives from the Secretary to the 

rated nameplate capacity of the taxpayer’s facility. For example, if the taxpayer receives an 

allocation of 750 megawatts of capacity from the Secretary and the taxpayer’s facility has a rated 

nameplate capacity of 1,000 megawatts, then the taxpayer may claim three-quarters of the 

otherwise allowable credit, or 1.35 cents per kilowatt-hour, for each kilowatt-hour of electricity 

produced at the facility (subject to the annual limitation described below). The Secretary may 

allocate a total of up to 6,000 megawatts of capacity. 

 138 The 1.8-cents credit amount is reduced, but not below zero, if the annual average contract 

price per kilowatt-hour of electricity generated from advanced nuclear power facilities in the preceding 

year exceeds eight cents per kilowatt-hour. The eight-cent price comparison level is indexed for inflation 

after 1992. 
93 

A taxpayer operating a qualified facility may claim no more than $125 million in tax 

credits per 1,000 megawatts of allocated capacity in any one year of the eight-year credit period. 

If the taxpayer operates a 1,350 megawatt rated nameplate capacity system and has received an 

allocation from the Secretary for 1,350 megawatts of capacity eligible for the credit, the 

taxpayer’s annual limitation on credits that may be claimed is equal to 1.35 times $125 million, 

or $168.75 million. If the taxpayer operates a facility with a nameplate rated capacity of 1,350 

megawatts, but has received an allocation from the Secretary for 750 megawatts of credit eligible 

capacity, then the two limitations apply such that the taxpayer may claim a credit equal to 1 cent 

per kilowatt-hour of electricity produced (as described above) subject to an annual credit 

limitation of $93.75 million in credits (three-quarters of $125 million). 

An advanced nuclear facility is any nuclear facility for the production of electricity, the 

reactor design for which was approved after 1993 by the Nuclear Regulatory Commission. For 

this purpose, a qualifying advanced nuclear facility does not include any facility for which a 

substantially similar design for a facility of comparable capacity was approved before 1994. 

In addition, the credit allowable to the taxpayer is reduced by reason of grants, taxexempt bonds, subsidized energy financing, and other credits, but such reduction cannot exceed 

50 percent of the otherwise allowable credit. The credit is treated as part of the general business 

credit. 

3. Credit for carbon dioxide sequestration (sec. 45Q) 

A credit of $10 per metric ton is available for qualified carbon dioxide that is captured by 

the taxpayer at a qualified facility, used by such taxpayer as a tertiary injectant (including carbon 

dioxide augmented waterflooding and immiscible carbon dioxide displacement) in a qualified 

enhanced oil or natural gas recovery project and disposed of by such taxpayer in secure 

geological storage.139 In addition, a credit of $20 per metric ton is available for qualified carbon 

dioxide captured by a taxpayer at a qualified facility and disposed of by such taxpayer in secure 

geological storage without being used as a tertiary injectant. Both credit amounts are adjusted 

for inflation after 2009. 

Secure geological storage includes storage at deep saline formations, oil and gas 

reservoirs, and unminable coal seams. The Secretary, in consultation with the Administrator of 

the Environmental Protection Agency the Secretary of Energy, and the Secretary of the Interior, 

is required to establish regulations for determining adequate security measures for the secure 

geological storage of carbon dioxide such that the carbon dioxide does not escape into the 

atmosphere. 

Qualified carbon dioxide is defined as carbon dioxide captured from an industrial source 

that (1) would otherwise be released into the atmosphere as an industrial emission of greenhouse 

gas, and (2) is measured at the source of capture and verified at the point or points of injection. 

Qualified carbon dioxide includes the initial deposit of captured carbon dioxide used as a tertiary 

injectant but does not include carbon dioxide that is recaptured, recycled, and re-injected as part 

 139 Sec. 45Q. 
94 

of an enhanced oil or natural gas recovery project process. A qualified enhanced oil or natural 

gas recovery project is a project that would otherwise meet the definition of an enhanced oil 

recovery project under section 43, if natural gas projects were included within that definition. 

A qualified facility means any industrial facility (1) which is owned by the taxpayer, (2) 

at which carbon capture equipment is placed in service, and (3) which captures not less than 

500,000 metric tons of carbon dioxide during the taxable year. The credit applies only with 

respect to qualified carbon dioxide captured and sequestered or injected in the United States140 or 

one of its possessions.141

Except as provided in regulations, credits are attributable to the person that captures and 

physically or contractually ensures the disposal, or use as a tertiary injectant, of the qualified 

carbon dioxide. Credits are subject to recapture, as provided by regulation, with respect to any 

qualified carbon dioxide that ceases to be recaptured, disposed of, or used as a tertiary injectant 

in a manner consistent with the rules of the provision. 

The credit is part of the general business credit. The credit sunsets at the end of the 

calendar year in which the Secretary, in consultation with the Administrator of the 

Environmental Protection Agency, certifies that 75 million metric tons of qualified carbon 

dioxide have been captured and sequestered. 

4. Advanced coal project credit (sec. 48A) 

In general

An investment tax credit is available for power generation projects that use integrated 

gasification combined cycle (“IGCC”) or other advanced coal-based electricity generation 

technologies. 

First round of credit allocations

For the first round of credit allocations, the credit amount is 20 percent for investments in 

qualifying IGCC projects and 15 percent for investments in qualifying projects that use other 

advanced coal-based electricity generation technologies. 

To qualify, an advanced coal project must be located in the United States and use an 

advanced coal-based generation technology to power a new electric generation unit or to retrofit 

or repower an existing unit. Generally, an electric generation unit using an advanced coal-based 

technology must be designed to achieve a 99-percent reduction in sulfur dioxide and a 90-percent 

reduction in mercury, as well as to limit emissions of nitrous oxide and particulate matter.142

 140 Sec. 638(1). 

141 Sec. 638(2). 

142 For advanced coal project certification applications submitted after October 2, 2006, an 

electric generation unit using advanced coal-based generation technology designed to use subbituminous 
95 

The fuel input for a qualifying project, when completed, must use at least 75 percent coal. 

The project, consisting of one or more electric generation units at one site, must have a 

nameplate generating capacity of at least 400 megawatts, and the taxpayer must provide evidence 

that a majority of the output of the project is reasonably expected to be acquired or utilized. 

Credits are available only for projects certified by the Secretary of Treasury, in 

consultation with the Secretary of Energy. Certifications are issued using a competitive bidding 

process. The Secretary of Treasury must establish a certification program no later than 180 days 

after August 8, 2005,143 and each project application must be submitted during the three-year 

period beginning on the date such certification program is established. An applicant for 

certification has two years from the date the Secretary accepts the application to provide the 

Secretary with evidence that the requirements for certification have been met. Upon 

certification, the applicant has five years from the date of issuance of the certification to place 

the project in service. 

The Secretary of Treasury may allocate $800 million of credits to IGCC projects and 

$500 million to projects using other advanced coal-based electricity generation technologies. 

Qualified projects must be economically feasible and use the appropriate clean coal technologies. 

With respect to IGCC projects, credit-eligible investments include only investments in property 

associated with the gasification of coal, including any coal handling and gas separation 

equipment. Thus, investments in equipment that could operate by drawing fuel directly from a 

natural gas pipeline do not qualify for the credit. 

In determining which projects to certify, the Secretary must allocate power generation 

capacity in relatively equal amounts to projects that use bituminous coal, subbituminous coal, 

and lignite as primary feedstock. In addition, the Secretary must give high priority to projects 

which include greenhouse gas capture capability, increased by-product utilization, and other 

benefits. 

Second round of credit allocations

Under the second round of credit allocations, the credit rate is increased to 30 percent for 

new IGCC and other advanced coal projects and the Secretary is permitted to allocate an 

additional $1.25 billion of credits to qualifying projects.144

 

coal can meet the performance requirement relating to the removal of sulfur dioxide if it is designed either 

to remove 99 percent of the sulfur dioxide or to achieve an emission limit of 0.04 pounds of sulfur 

dioxide per million British thermal units on a 30-day average. 

143 The Secretary issued guidance establishing the certification program on February 21, 2006 

(IRS Notice 2006-24). 

144 The second round of credit allocations were authorized on October 3, 2008, the date of 

enactment of the Energy Improvement and Extension Act of 2008 (Pub. Law 110-343, Div. B). 
96 

Under the second round of credit allocations, qualifying projects must include equipment 

which separates and sequesters at least 65 percent of the project’s total carbon dioxide emissions. 

This percentage increases to 70 percent if the credits are later reallocated by the Secretary. The 

Secretary is required to recapture the benefit of any allocated credit if a project fails to attain or 

maintain these carbon dioxide separation and sequestration requirements. 

In selecting projects, the Secretary must give high priority to applicants who have a 

research partnership with an eligible educational institution. In addition, the Secretary must give 

the highest priority to projects with the greatest separation and sequestration percentage of total 

carbon dioxide emissions. The Secretary must also disclose which projects receive credit 

allocations, including the identity of the taxpayer and the amount of the credit awarded. 

5. Gasification investment credit (sec. 48B) 

In general

An investment credit is available for certain qualifying gasification projects. Only 

property which is part of a qualifying gasification project and necessary for the gasification 

technology of such project is eligible for the gasification credit. 

First round of credit allocations

Under the first round of credit allocations, a 20-percent investment tax credit is available 

for investments in certain qualifying gasification projects. Qualified gasification projects convert 

coal, petroleum residue, biomass, or other materials recovered for their energy or feedstock value 

into a synthesis gas composed primarily of carbon monoxide and hydrogen for direct use or 

subsequent chemical or physical conversion. Qualified projects must be carried out by an 

eligible entity, defined as any person whose application for certification is principally intended 

for use in a domestic project which employs domestic gasification applications related to (1) 

chemicals, (2) fertilizers, (3) glass, (4) steel, (5) petroleum residues, (6) forest products, and (7) 

agriculture, including feedlots and dairy operations. 

Credits are available only for projects certified by the Secretary of Treasury, in 

consultation with the Secretary of Energy. Certifications are issued using a competitive bidding 

process. The Secretary of Treasury must establish a certification program no later than 180 days 

after August 8, 2005,145 and each project application must be submitted during the 3-year period 

beginning on the date such certification program is established. The Secretary of Treasury may 

not allocate more than $350 million in credits. In addition, the Secretary may certify a maximum 

of $650 million in qualified investment as eligible for credit with respect to any single project. 

 145 The Secretary issued guidance establishing the certification program on February 21, 2006 

(IRS Notice 2006-25). 
97 

Second round of credit allocations

Under the second round of credit allocations, the gasification project credit rate is 

increased to 30 percent and the Secretary is authorized to allocate an additional $250 million of 

credits to qualified projects that separate and sequester at least 75 percent of total carbon dioxide 

emissions.146 For this round, the definition of credit-eligible entities includes entities whose 

gasification projects are related to the production of transportation grade liquid fuels. The 

Secretary is required to recapture the benefit of any allocated credit if a project fails to attain or 

maintain these carbon dioxide separation and sequestration requirements. 

In selecting projects, the Secretary must give high priority to applicants who have a 

research partnership with an eligible educational institution. In addition, the Secretary must give 

the highest priority to projects with the greatest separation and sequestration percentage of total 

carbon dioxide emissions. The Secretary must also disclose which projects receive credit 

allocations, including the identity of the taxpayer and the amount of the credit awarded. 

6. Pollution Control Facilities (sec. 169) 

In general, a taxpayer may elect to recover the cost of any certified pollution control 

facility over a period of 60 months.147 A certified pollution control facility is defined as a new, 

identifiable treatment facility which (1) is used in connection with a plant in operation before 

January 1, 1976, to abate or control water or atmospheric pollution or contamination by 

removing, altering, disposing, storing, or preventing the creation or emission of pollutants, 

contaminants, wastes or heat; and (2) does not lead to a significant increase in output or capacity, 

a significant extension of useful life, a significant reduction in total operating costs for such plant 

or other property (or any unit thereof), or a significant alteration in the nature of a manufacturing 

production process or facility. Certification is required by appropriate State and Federal 

authorities that the facility complies with appropriate standards. 

For a pollution control facility with a useful life greater than 15 years, only the portion of 

the basis attributable to the first 15 years is eligible to be amortized over a 60-month period.148 

In addition, a corporate taxpayer must reduce the amount of basis otherwise eligible for the 60-

month recovery by 20 percent.149 The amount of basis not eligible for 60-month amortization is 

depreciable under the regular tax rules for depreciation. 

 146 The second round of credit allocations were authorized on October 3, 2008, the date of 

enactment of the Energy Improvement and Extension Act of 2008 (Pub. Law 110-343, Div. B). 

147 Sec. 169. 

148 The amount attributable to the first 15 years is equal to an amount which bears the same ratio 

to the portion of the adjusted basis of the facility, which would be eligible for amortization but for the 

application of this rule, as 15 bears to the number of years of useful life of the facility. 

149 Sec. 291(a)(4). 
98 

A certified air pollution control facility (but not a water pollution control facility) used in 

connection with an electric generation plant which is primarily coal fired will be eligible for 84-

month amortization if the associated plant or other property was not in operation prior to 

January 1, 1976.150 The 60-month amortization period remains in effect for any certified air 

pollution control facility used in connection with an electric generation plant which is primarily 

coal fired and which was in operation prior to January 1, 1976. 

7. Special rules for nuclear decommissioning costs (sec. 468A) 

In general

Special rules dealing with nuclear decommissioning reserve funds were enacted in the 

Deficit Reduction Act of 1984 (“1984 Act”), when tax issues regarding the time value of money 

were addressed generally. Under general tax accounting rules, a deduction for accrual basis 

taxpayers is deferred until there is economic performance for the item for which the deduction is 

claimed. However, the 1984 Act contains an exception under which a taxpayer responsible for 

nuclear power plant decommissioning may elect to deduct contributions made to a qualified 

nuclear decommissioning fund for future decommissioning costs. Taxpayers who do not elect 

this provision are subject to general tax accounting rules. 

Qualified nuclear decommissioning fund

A qualified nuclear decommissioning fund (a “qualified fund”) is a segregated fund 

established by a taxpayer that is used exclusively for the payment of decommissioning costs, 

taxes on fund income, management costs of the fund, and for making investments. The income 

of the fund is taxed at a reduced rate of 20 percent. 

At the election of the taxpayer, a deduction is allowed for any taxable year in the amount 

of payments made by the taxpayer to a qualified fund. Amounts withdrawn by the taxpayer to 

pay for decommissioning costs are included in the taxpayer’s income, but the taxpayer also is 

entitled to a deduction for decommissioning costs as economic performance for such costs 

occurs. 

Accumulations in a qualified fund are limited to the amounts sufficient to cover the 

present value of a nuclear power plant’s estimated decommissioning costs. In order to prevent 

accumulations of funds over the useful life of a nuclear power plant in excess of those required 

to pay decommissioning costs of such nuclear power plant and to ensure that contributions to a 

qualified fund are not deducted more rapidly than level funding (taking into account an 

appropriate discount rate), taxpayers must obtain a ruling from the IRS to establish the maximum 

annual contribution that may be made to a qualified fund (the “ruling amount”). In certain 

instances (e.g., change in estimates), a taxpayer is required to obtain a new ruling amount to 

reflect updated information. 

 150 This provision was added by the Energy Policy Act of 2005 (Pub. L. No. 109-58) and is 

generally applicable to property that is constructed or acquired after April 11, 2005. 
99 

A qualified fund may be transferred in connection with the sale, exchange or other 

transfer of the nuclear power plant to which it relates. If the transferee is a regulated public 

utility and meets certain other requirements, the transfer will be treated as a nontaxable 

transaction. No gain or loss will be recognized on the transfer of the qualified fund and the 

transferee will take the transferor’s basis in the fund. The transferee is generally required to 

obtain a new ruling amount from the IRS. 
100 

G. Provisions Relating to General Energy-Related Projects and Research 

1. Energy research credit (sec. 41) 

General rule

A 20-percent credit is available for a taxpayer’s expenditures on qualified research 

undertaken by an energy research consortium. Generally, an energy research consortium is an 

organization (not including a private foundation) that is either (1) a tax-exempt section 501(c)(3) 

corporation organized and operated primarily to conduct energy research or (2) any other 

organization organized and operated primarily to conduct energy research in the public interest 

(within the meaning of section 501(c)(3)). In addition, an energy research consortium must have 

received payments or contributions for energy research from at least 5 unrelated persons per year 

and no single person can have paid or contributed a majority of the funds used for such research. 

The energy research credit expires for amounts paid or incurred after December 31, 

2009.151

Qualified research

Qualified research expenses eligible for the research tax credit consist of: (1) in-house 

expenses of the taxpayer for wages and supplies attributable to qualified research; (2) certain 

time-sharing costs for computer use in qualified research; and (3) 65 percent of amounts paid or 

incurred by the taxpayer to certain other persons for qualified research conducted on the 

taxpayer’s behalf (so-called contract research expenses).152 Notwithstanding the limitation for 

contract research expenses, qualified research expenses include 100 percent of amounts paid or 

incurred by the taxpayer to an eligible small business, university, or Federal laboratory for 

qualified energy research. 

To be eligible for the credit, the research not only has to satisfy the requirements of 

present-law section 174 (described below) but also must be undertaken for the purpose of 

discovering information that is technological in nature, the application of which is intended to be 

useful in the development of a new or improved business component of the taxpayer, and 

substantially all of the activities of which constitute elements of a process of experimentation for 

functional aspects, performance, reliability, or quality of a business component. Research does 

not qualify for the credit if substantially all of the activities relate to style, taste, cosmetic, or 

 151 Sec. 41(h). 

152 Under a special rule, 75 percent of amounts paid to a research consortium for qualified 

research are treated as qualified research expenses eligible for the research credit (rather than 65 percent 

under the general rule under section 41(b)(3) governing contract research expenses) if (1) such research 

consortium is a tax-exempt organization that is described in section 501(c)(3) (other than a private 

foundation) or section 501(c)(6) and is organized and operated primarily to conduct scientific research, 

and (2) such qualified research is conducted by the consortium on behalf of the taxpayer and one or more 

persons not related to the taxpayer. Sec. 41(b)(3)(C). 
101 

seasonal design factors.153 In addition, research does not qualify for the credit: (1) if conducted 

after the beginning of commercial production of the business component; (2) if related to the 

adaptation of an existing business component to a particular customer’s requirements; (3) if 

related to the duplication of an existing business component from a physical examination of the 

component itself or certain other information; or (4) if related to certain efficiency surveys, 

management function or technique, market research, market testing, or market development, 

routine data collection or routine quality control.154 Research does not qualify for the credit if it 

is conducted outside the United States, Puerto Rico, or any U.S. possession. 

Relation to deduction

Under section 174, taxpayers may elect to deduct currently the amount of certain research 

or experimental expenditures paid or incurred in connection with a trade or business, 

notwithstanding the general rule that business expenses to develop or create an asset that has a 

useful life extending beyond the current year must be capitalized.155 However, deductions 

allowed to a taxpayer under section 174 (or any other section) are reduced by an amount equal to 

100 percent of the taxpayer’s research tax credit determined for the taxable year.156 Taxpayers 

may alternatively elect to claim a reduced research tax credit amount under section 41 in lieu of 

reducing deductions otherwise allowed.157

2. Credit for investment in advanced energy property (sec. 48C) 

A 30-percent credit for investment in qualified property used in a qualified advanced 

energy manufacturing project. A qualified advanced energy project is a project that re-equips, 

expands, or establishes a manufacturing facility for the production: (1) property designed to be 

used to produce energy from the sun, wind, or geothermal deposits (within the meaning of 

section 613(e)(2)), or other renewable resources; (2) fuel cells, microturbines, or an energy 

storage system for use with electric or hybrid-electric motor vehicles; (3) electric grids to support 

the transmission of intermittent sources of renewable energy, including storage of such energy; 

(4) property designed to capture and sequester carbon dioxide; (5) property designed to refine or 

blend renewable fuels (but not fossil fuels) or to produce energy conservation technologies 

(including energy-conserving lighting technologies and smart grid technologies); (6) new 

qualified plug-in electric drive motor vehicles, qualified plug-in electric vehicles, or components 

which are designed specifically for use with such vehicles, including electric motors, generators, 

and power control units, or (7) other advanced energy property designed to reduce greenhouse 

gas emissions as may be determined by the Secretary. Qualified property does not include 

 153 Sec. 41(d)(3). 

154 Sec. 41(d)(4). 

155 Taxpayers may elect 10-year amortization of certain research expenditures allowable as a 

deduction under section 174(a). Secs. 174(f)(2) and 59(e). 

156 Sec. 280C(c). 

157 Sec. 280C(c)(3). 
102 

property designed to manufacture equipment for use in the refining or blending of any 

transportation fuel other than renewable fuels. 

Qualified property must be depreciable (or amortizable) property used in a qualified 

advanced energy project. Only tangible personal property and other tangible property (not 

including a building or its structural components) are credit-eligible. The basis of qualified 

property must be reduced by the amount of credit received. 

Credits are available only for projects certified by the Secretary of Treasury, in 

consultation with the Secretary of Energy. The Secretary of Treasury must establish a 

certification program no later than 180 days after February 17, 2009 (the date of enactment of the 

American Recovery and Reinvestment Act of 2009), and may allocate up to $2.3 billion in 

credits. No credit is allowed for any qualified investment that was allowed a credit under 

sections 48, 48A, or 48B. 

In selecting projects, the Secretary may consider only those projects where there is a 

reasonable expectation of commercial viability. In addition, the Secretary must consider other 

selection criteria, including which projects (1) will provide the greatest domestic job creation; (2) 

will provide the greatest net impact in avoiding or reducing air pollutants or anthropogenic 

emissions of greenhouse gases; (3) have the greatest potential for technological innovation and 

commercial deployment; (4) have the lowest levelized cost of generated or stored energy, or of 

measured reduction in energy consumption or greenhouse gas emission; and (5) have the shortest 

project time from certification to completion. 

Each project application must be submitted during the two-year period beginning on the 

date such certification program is established. An applicant for certification has one year from 

the date the Secretary accepts the application to provide the Secretary with evidence that the 

requirements for certification have been met. Upon certification, the applicant has three years 

from the date of issuance of the certification to place the project in service. Not later than four 

years after the date of enactment of the credit, the Secretary is required to review the credit 

allocations and redistribute any credits that were not used either because of a revoked 

certification or because of an insufficient quantity of credit applications. 
103 

H. Miscellaneous Energy Provisions 

1. Tax-exempt bonds for power facilities (secs. 103, 141, and 142) 

In general

Interest on bonds issued by State and local governments generally is excluded from gross 

income for Federal income tax purposes.158 Because the interest income is excluded from gross 

income, investors generally are willing to accept a lower rate on on tax-exempt bonds than they 

might otherwise accept on a taxable investment. Thus, issuers of such bonds receive an implicit 

Federal subsidy equal to the difference between the tax-exempt interest rate paid and the taxable 

rate that otherwise would be paid. In this way, the income exclusion lowers the cost of capital 

for State and local government. Activities that can be financed with tax-exempt bonds issued by 

State and local governments include electric power facilities (i.e., generation, transmission, 

distribution, and retailing). 

Bonds issued by State and local governments may be classified as either governmental 

bonds or private activity bonds. Governmental bonds are bonds the proceeds of which are 

primarily used to finance governmental functions or which are repaid with governmental funds. 

Private activity bonds are bonds in which the State or local government serves as a conduit 

providing financing to nongovernmental persons. For these purposes, the term 

“nongovernmental person” generally includes the Federal Government and all other individuals 

and entities other than States or local governments. The exclusion from income for interest on 

State and local bonds does not apply to private activity bonds, unless the bonds are issued for 

certain permitted purposes (“qualified private activity bonds”) and other Code requirements are 

met. 

Private activity bond tests

Present law provides two tests for determining whether a State or local bond is in 

substance a private activity bond and, as a result, not a governmental bond, the private business 

test and the private loan test.159 

Private business tests

Private business use and private payments result in State and local bonds being private 

activity bonds if both parts of the two-part private business test are satisfied-- 

1. More than 10 percent of the bond proceeds is to be used (directly or indirectly) by a 

private business (the “private business use test”); and 

 158 Sec. 103(a). 

159 Secs. 141(b) and (c). 
104 

2. More than 10 percent of the debt service on the bonds is secured by an interest in 

property to be used in a private business use or to be derived from payments in respect 

of such property (the “private payment test”).160 

Private business use generally includes any use by a business entity (including the 

Federal government), which occurs pursuant to terms not generally available to the general 

public. For example, if bond-financed property is leased to a private business (other than 

pursuant to certain short-term leases for which safe harbors are provided under Treasury 

regulations), bond proceeds used to finance the property are treated as used in a private business 

use, and rental payments are treated as securing the payment of the bonds. Similarly, in the case 

of public power entities, if output of an electric generating plant or transmission or distribution 

facilities is provided to a private business on terms not generally available to other customers of 

the entity, an allocable portion of bonds financing the facilities is treated as used in a private 

business use and as secured by the payments from the private business. 

Private business use also can arise when a governmental entity contracts for the operation 

of a governmental facility by a private business under a management contract that does not 

satisfy Treasury regulatory safe harbors regarding the types of payments made to the private 

operator and the length of the contract.161 These rules require public power entities to restrict the 

period of contracts with private businesses as well as the aggregate amount of electric service 

provided to private businesses on terms that are not generally available to customers of the 

entity, if interest on their bonds is to remain tax-exempt. 

Private loan test

The second standard for determining whether a State or local bond is a private activity 

bond is whether an amount exceeding the lesser of (1) five percent of the bond proceeds or (2) $5 

million is used (directly or indirectly) to finance loans to private persons. Private loans include 

both business and other (e.g., personal) uses and payments by private persons; however, in the 

case of business uses and payments, all private loans also constitute private business uses and 

payments subject to the private business test. Present law provides that the substance of a 

transaction governs in determining whether the transaction gives rise to a private loan. In 

general, any transaction which transfers tax ownership of property to a private person is treated 

as a loan. In the context of public power, longer-term contracts for the sale of output may violate 

the private loan test, because these contracts have the substantive characteristics of a loan. 

Under the Energy Policy Act of 2005, qualified natural gas contracts are not treated as 

private loans for purposes of the private business tests. A contract is a qualified natural gas 

 160 The 10-percent private business use and payment threshold is reduced to five percent for 

private business uses that are unrelated to a governmental purpose also being financed with proceeds of 

the bond issue. In addition, as described more fully below, the 10-percent private business use and 

private payment thresholds are phased-down for larger bond issues for the financing of certain “output” 

facilities. The term output facility includes electric generation, transmission, and distribution facilities. 

161 See Treas. Reg. sec. 1.141-3(b)(4) and Rev. Proc. 97-13, 1997-1 C.B. 632. 
105 

contract if the volume of natural gas secured for any year covered by the bond-financed contract 

does not exceed the sum of (1) the average annual natural gas purchased (other than for resale) 

by customers of a governmental utility within the service area of the utility (“retail natural gas 

consumption”) during a testing period, and (2) the amount of natural gas that is needed to fuel 

transportation of the natural gas to the governmental utility. For purposes of this rule, the testing 

period is the 5-calendar-year period immediately preceding the calendar year in which the bonds 

are issued. A retail customer is one who does not purchase natural gas for resale. 

Special legislative rules for tax-exempt financing of governmental “output” facilities

In addition to the general private business use and payment tests, the Code includes 

specific provisions governing the issuance of governmental tax-exempt bonds to finance 

“output” facilities. Output facilities include facilities for electric and gas generation, 

transmission, and distribution. 

$15 million limit on private business use.–Present law imposes an additional restriction 

on private business use of State or local government bonds whose proceeds are to be used to 

finance output facilities.162 A bond is treated as issued to finance an output facility (and subject 

to this restriction) if five percent or more of the proceeds is to be used with respect to any output 

facility. Under this restriction, the 10-percent private business use and private payment tests in 

substance are phased down for facilities that receive more than $15 million in tax-exempt bond 

financing. Significantly, unlike most tax-exempt bond restrictions, which are determined on a 

bond-issue by bond-issue basis, this restriction is measured by reference to all outstanding taxexempt financing from which a facility benefits. 

Bonds for acquisition of existing output property per se private activity.–In general, any 

bond with respect to which five percent or more ($5 million if less) of the proceeds is to be used, 

directly or indirectly, by a governmental entity to acquire existing output property is per se a 

private activity bond.163 As such, interest on the bond is taxable, unless the use of the acquired 

facility satisfies the provisions applicable to tax-exempt private activity bonds for the local 

furnishing of electricity (described below). The two-county (or a city and a contiguous county) 

service area requirement that applies to facilities for the local furnishing of electricity does not 

apply in this circumstance. 

There are two exceptions to the rule regarding the acquisition of existing output property. 

First, the rule does not apply to bonds for the acquisition of existing facilities that will provide 

service in a “qualified service area” of the issuer. A qualified service area is defined as an area 

throughout which the acquiring entity has provided electric service for at least the 10-year period 

preceding the date of the acquisition. Second, the rule does not apply to bonds issued to acquire 

existing output property to be used in a “qualified annexed area” of a public power entity. The 

term qualified annexed area includes only areas (1) that are contiguous to existing service areas, 

 162 Sec. 141(b)(4). 

163 Sec. 141(d). 
106 

(2) that are annexed for general governmental purposes, and (3) the size of which does not 

exceed 10 percent of the public power entity’s service area before the annexation occurs. 

In addition, under the Energy Policy Act of 2005, qualified natural gas contracts (as 

defined above) are not treated as nongovernmental output property for purposes of the 

restrictions on the acquisition of such property. 

Qualified private activity bonds

In general

As stated above, interest on private activity bonds is taxable unless the bonds meet the 

requirements for qualified private activity bonds. Qualified private activity bonds permit States 

or local governments to act as conduits providing tax-exempt financing for certain private 

activities. In most cases, the aggregate volume of these tax-exempt private activity bonds is 

restricted by annual aggregate volume limits imposed on bonds issued by issuers within each 

State. The Code further imposes several additional restrictions on tax-exempt private activity 

bonds that do not apply to bonds for governmental activities. 

The definition of qualified private activity bonds includes an exempt facility bond, or 

qualified mortgage, veterans’ mortgage, small issue, redevelopment, 501(c)(3), or student loan 

bond (sec. 141(e)). The definition of exempt facility bond includes bonds issued to finance 

certain transportation facilities (airports, ports, mass commuting, and high-speed intercity rail 

facilities); qualified residential rental projects; privately owned and/or operated utility facilities 

(sewage, water, solid waste disposal, and local district heating and cooling facilities, certain 

private electric and gas facilities, and hydroelectric dam enhancements); public/private 

educational facilities; qualified green building and sustainable design projects; and qualified 

highway or surface freight transfer facilities (sec. 142(a)). 

Private activity bonds for the local furnishing of electricity

Qualified private activity bonds may be issued by States or local governments acting as 

conduits to finance generation, transmission, and distribution facilities for private businesses 

engaged in the local furnishing of electricity (“local furnishers”). A business is treated as 

engaged in local furnishing of electricity if the service territory in which the electricity is 

provided does not exceed (1) two contiguous counties, or (2) a city and a contiguous county. 

Historically, local furnishers eligible for this tax-exempt financing have included both investorowned utilities (“IOUs”) and independent power ventures. These bonds may be issued for the 

benefit of only those persons that were engaged in local furnishing of electricity in the service 

territory in which the new facilities will be used as of January 1, 1997, or in qualified expansions 

of those service territories. A “qualified expansion” is limited to service territory that is a part of 

a county in which the local furnisher was providing electric service on that date. For example, if 

a local furnisher was providing electric service to one county and a portion of a contiguous 

county on January 1, 1997, bonds may be issued for the continued provision of service both 

within that area and also for service to be provided in the remaining portion of the contiguous 

county in the future. In addition to persons actually engaged in local furnishing activities on 

January 1, 1997, the Code allows certain successors in interest to persons that qualified as local 
107 

furnishers on that date to “step into the shoes” of the predecessor local furnishers provided that 

the service territories served otherwise satisfy the requirements for local furnishing. 

Notwithstanding the general limits on service territories of local furnishers, the Code 

includes special rules allowing these electric service providers to transmit (“wheel”) electricity 

through their systems, if ordered by the Federal Energy Regulatory Commission to do so under 

sections 211 or 213 of the Federal Power Act, provided that the size of the transmission lines or 

other facilities used in these wheeling activities does not exceed the capacity required to serve 

their otherwise qualified two contiguous county service area or city and contiguous county 

service area. 

Hydro-electric generating facilities

Present law also permits the issuance of qualified private activity bonds for 

“environmental enhancements of hydro-electric generating facilities.” Eligible facilities include 

those that protect or promote fisheries or other wildlife resources and those for recreational 

purposes or other improvements required by the terms of a Federal license for the operation of a 

hydro-electric generating facilities. This provision was enacted to permit tax-exempt financing 

of certain renovations to the dams and accompanying hydroelectric electric generating facilities 

along the Columbia River that are a part of the Bonneville Power Administration system. Bonds 

issued for these purposes are not subject to the State volume limitations applicable to most 

qualified private activity bonds. 

2. Reduced rate of tax for diesel-water fuel emulsion (secs. 4081(a)(2)(D), 4081(c), and 

6427(m)) 

Diesel fuel is taxed at 24.3 cents per gallon. A special tax rate of 19.7 cents per gallon is 

provided for diesel fuel blended with water into a diesel-water fuel emulsion to reflect the 

reduced Btu content per gallon resulting from the water. Emulsion fuels eligible for the special 

rate must consist of at least 14 percent water. The emulsion additive must be registered by a 

United States manufacturer with the Environmental Protection Agency pursuant to section 211 of 

the Clean Air Act (as in effect on March 31, 2003). A refund of the difference between the 

regular rate for diesel fuel (24.3 cents per gallon) and the incentive rate for diesel-water 

emulsions (19.7 cents per gallon) is available to the extent tax-paid diesel is used to produce a 

qualifying emulsion diesel fuel. Anyone who separates the diesel fuel from the diesel-water fuel 

emulsion on which a reduced rate of tax was imposed is treated as a refiner of the fuel and is 

liable for the difference between the amount of tax on the latest removal of the separated fuel and 

the amount of tax that was imposed upon the pre-mixture removal. The special tax rate does not 

apply if the person removing, selling or using such fuel is not registered with the IRS. 

3. Exceptions for publicly traded partnerships treated as corporations (secs. 7704 and 851) 

Treatment as a corporation

Present law provides that a publicly traded partnership means a partnership, interests in 

which are traded on an established securities market, or are readily tradable on a secondary 

market (or the substantial equivalent thereof). In general, a publicly traded partnership is treated 

as a corporation, but an exception to corporate treatment is provided if 90 percent or more of its 
108 

gross income is interest, dividends, real property rents, or certain other types of qualifying 

income.164 

Under this exception, income and gains from certain activities with respect to minerals or 

natural resources are treated as qualifying income. Specifically, among other types of income, 

qualifying income includes income and gains derived from the exploration, development, mining 

or production, processing, refining, transportation (including pipelines transporting gas, oil, or 

products thereof), or the marketing of any mineral or natural resource (including fertilizer, 

geothermal energy, and timber). For this purpose, oil, gas, or products thereof means gasoline, 

kerosene, number 2 fuel oil, refined lubricating oils, diesel fuel, methane, butane, propane, and 

similar products which are recovered from petroleum refineries or field facilities. Oil, gas, or 

products thereof are not intended to encompass oil or gas products that are produced by 

additional processing beyond that of petroleum refineries or field facilities, such as plastics or 

similar petroleum derivatives. 

Qualifying income for regulated investment companies

A regulated investment company (RIC) generally is treated as a conduit for Federal 

income tax purposes. To qualify for conduit treatment, at least 90 percent of the RIC’s gross 

income must fall within specified categories (dividends, interest, and other specified types). 

Income derived from a partnership generally is treated as meeting this requirement only to the 

extent such income is attributable to items of income of the partnership that would meet the 

requirement if realized by the RIC in the same manner as realized by the partnership (the “lookthrough” rule for partnership income).165

In the case of a publicly traded partnership, present law provides that the 90-percent test 

with respect to income of a RIC includes net income derived from an interest in a publicly traded 

partnership. The look-through rule for partnership income of a RIC applies only to income from 

a partnership other than a publicly traded partnership. 

 164 Sec. 7704. 

165 Sec. 851. 
109 

III. DATA AND ANALYSIS 

Energy tax expenditures and sources of U.S. energy supply

Table 9, below, shows the staff of the Joint Committee on Taxation’s most recent 

estimates of the energy-specific tax expenditures. The largest tax expenditure items generally 

occur in the oil and gas industries, owing at least in part to the relative size of such industries as 

compared to the renewable energy sector. 

In recent years there has been increased interest in providing tax subsidies for 

conservation of energy and for development of renewable sources of energy. However, the 

United States continues to rely primarily on fossil fuel sources for energy. In 2007, 85 percent of 

U.S. energy supply came from fossil fuels, eight percent from nuclear electric power, and only 

seven percent from renewable sources of energy. Chart 1, below, shows the distribution of the 

U.S. energy supply by source of energy − petroleum, natural gas, coal, nuclear, and renewable. 

Chart 1.−The Role of Renewable Energy Consumption in the Nation’s 

Energy Supply, 2007 

Source: Energy Information Administration, Renewable Energy Consumption and Electricity Preliminary 2007 

Statistics, May 2008. 
Corporations In

Function 2008 2009 2010 2011 2012 2008 2009 

Energy related credits:Credit for enhanced oil recovery costs.............................................. [1] [1] [1] [1] [1] [1] [1] Credit for producing fuels from a non-conventional source............. 0.1 0.1 [1] [1] [1] [1] [1] Credits for alcohol fuels [2].............................................................. 0.1 0.1 0.1 [1] --- --- --- Energy credit (section 48):

Solar............................................................................................... [1] [1] [1] [1] [1] [1] [1] Geothermal..................................................................................... [1] [1] [1] [1] [1] [1] [1] Fuel cells........................................................................................ [1] [1] [1] [1] [1] [1] [1] Microturbines................................................................................. --- --- --- --- --- [1] [1] 

Credits for electricity production from renewable resources (section 45):

Wind.............................................................................................. 0.6 0.8 0.9 0.9 0.9 [1] [1] Closed-loop biomass...................................................................... [1] [1] [1] [1] [1] --- --- Geothermal..................................................................................... [1] [1] [1] [1] [1] --- --- Qualified hydropower.................................................................... [1] [1] [1] [1] [1] --- --- Solar (limited to facilities placed in service before 1/1/06)........... [1] [1] [1] [1] [1] --- --- Small irrigation power................................................................... [1] [1] [1] [1] [1] --- --- Municipal solid waste.................................................................... [1] [1] [1] [1] [1] --- --- Open-loop biomass........................................................................ 0.3 0.4 0.3 0.2 0.2 [1] [1] 

Credits for investments in clean coal facilities................................. 0.2 0.2 0.2 0.1 0.1 --- --- Coal production credits: Refined coal.................................................................................... [1] [1] [1] [1] [1] --- ---  Indian coal...................................................................................... [1] [1] [1] [1] [1] --- --- 

Credit for the production of energy-efficient appliances.................. 0.1 0.1 0.1 [1] --- --- --- Credits for alternative technology vehicles: Hybrid vehicles............................................................................... [1] [1] [1] [1] [1] 0.2 0.2 

Table 9.

−Energy-Related Tax Expenditure Estimates, Fiscal Years 2008 - 2012 

[Billions of Dollars] 
Corporations In

Function 2008 2009 2010 2011 2012 2008 2009 

 Other alternative fuel vehicles........................................................ [1] [1] [1] [1] [1] [1] [1] Credit for clean-fuel vehicle refueling property............................... [1] [1] [1] [1] [1] [1] [1] Residential energy efficient property credit...................................... --- --- --- --- --- [1] [1] New energy efficient home credit..................................................... [1] [1] [1] [1] [1] --- --- Credit for energy efficiency improvements to existing homes......... --- --- --- --- --- 0.8 0.3 Credits for alternative technology vehicles....................................... 0.1 [1] [1] [1] [1] 0.2 0.2 Credit for holders of clean renewable energy bonds......................... [1] 0.1 0.1 0.1 0.1 [1] [1] Credit for holder of qualified energy conservation bonds................. [1] [1] [1] [1] [1] [1] [1] Energy-related exclusions from income:Exclusion of interest on State and local government qualified private activity bonds for energy production facilities................... [1] [1] [1] [1] [1] 0.1 0.1 Exclusion of energy conservation subsidies provided by public utilities................................................................................. --- --- --- --- --- [1] [1] Energy-related deductions:Deduction for expenditures on energy-efficient commercial building property............................................................................ [1] 0.1 0.1 0.1 0.1 [1] [1] Eight-year inclusion from sale of electric transmission assets to independent utilities........................................................................ 0.3 0.2 [1] -0.1 -0.1 [1] [1] Expensing of exploration and development costs: Oil and gas...................................................................................... 2.1 3.0 1.7 0.4 0.4 [1] [1]  Other fuels...................................................................................... [1] [1] [1] [1] [1] [1] [1] Excess of percentage over cost depletion: Oil and gas...................................................................................... 1.3 1.4 1.4 1.4 1.4 [1] [1]  Other fuels...................................................................................... 0.1 0.1 0.1 0.1 0.1 [1] [1] Amortization of geological and geophysical expenditures associated with oil and gas exploration.......................................... 0.1 0.2 0.2 0.2 0.2 [1] 0.1 Amortization of air pollution control facilities................................. 0.1 0.1 0.1 0.2 0.2 [1] [1] Depreciation recovery periods for energy specific items: Five-year MACRS for certain energy property (solar, wind, etc.).. 0.2 0.1 0.1 0.1 0.1 [1] [1]  10-year MACRS for smart electric distribution property............... [1] [1] [1] [1] [1] 0.1 [1] 
Corporations In

Function 2008 2009 2010 2011 2012 2008 2009 

 15-year MACRS for certain electric transmission property............ [1] 0.1 0.1 0.2 0.2 [1] [1]  15-year MACRS for natural gas distribution line........................... 0.1 0.1 0.1 0.1 0.1 [1] [1] Election to expense 50 percent of qualified property used to refine liquid fuels............................................................................ 0.4 1.1 0.9 0.8 0.6 [1] [1] Exceptions for publicly traded partnership with qualified income derived from certain energy-related activities................................ --- --- --- --- --- 0.4 0.4 

Joint Committee on Taxation. Estimates based on the January 2008 Congressional Budget Office baseline for tax expenditures under present law as of October 31, 2

-------------------------------------------- NOTE: Details may not add to totals due to rounding.

[1] Positive tax expenditure of less than $50 million. [2] In addition, the credit from excise tax for alcohol fuels results in a reduction in excise tax receipts, net of income tax effect, of

$13.6 billion over the fiscal years 2008 through 2012.
113 

General economic rationale for certain tax expenditure intervention in energy markets

A common economic rationale for government intervention in certain markets (including 

many aspects of energy markets) is that often there exist “externalities” in the consumption or 

production of certain goods that lead to “market failures,” wherein either too little or too much of 

certain economic activity occurs relative to what is the socially optimal level of activity. An 

externality exists when, in the consumption or production of a good, there is a difference 

between the cost or benefit to an individual from consumption or production and the cost or 

benefit to society as a whole. When the society-wide, or “social” costs of consumption exceed 

the private costs of consumption, a negative externality exists. When the social benefits from 

consumption or production exceed private benefits, a positive externality exists. When negative 

externalities exist, there will be over-consumption of the good causing the negative externality 

relative to what would be socially optimal. When positive externalities exist, there will be under 

consumption of the good producing the positive externality. The reason for the over 

consumption or under consumption is that private actors will in general not take into account the 

effect of their consumption on others, but only weigh their personal costs and benefits in their 

decisions. Thus, they will consume goods up to the point where their marginal benefit of more 

consumption is equal to the marginal cost (generally, the price) that they face. But from a social 

perspective, consumption should occur up to the point where the marginal social cost (generally, 

the price to the consumer plus any external costs imposed on others) is equal to the marginal 

social benefit (the benefit received by the consumer, plus any social benefit from the individual 

consumption). Absent any government intervention, only when there are no externalities will the 

private actions lead to the socially optimal level of consumption or production, because only in 

this case will private costs and benefits be equal to social costs and benefits. 

As a general matter of economic efficiency, tax preferences designed to influence 

investment choices should be used only when it is acknowledged that market-based pricing 

signals have led to a lower level of investment in a good than would be socially optimal. In 

general, this can occur in a market-based economy when private investors do not capture the full 

value of an investment−that is, when there are positive externalities to the investment that accrue 

to third parties who did not bear any of the costs of the investments. For example, if an 

individual or corporation can borrow funds at 10 percent and make an investment that will return 

15 percent, they will generally make that investment. However, if the return were 15 percent, 

but only 8 percent of that return went to the investor, and seven percent to society at large, the 

investment will generally not take place, even though the social return (the sum of the return to 

the investor and other parties) would indicate that the investment should be made. In such a 

situation, it may be desirable to subsidize the return to the investor through tax credits or other 

mechanisms in order that the investor’s return is sufficient to cause the socially desirable 

investment to be made. In this example, a credit that raises the return to the investor to at least 

10 percent would be necessary. Even if the cost of the credit were paid through general tax 

increases for others, they would presumably be better off since they enjoy a seven percent return 

from the investment, and the credit would only need to raise the return to the investor by two 

percent for him or her to break even. Thus, even if the rest of society bears the full cost of the 

credit, they would enjoy a five-percent net return to the investment (seven percent less two 

percent). 
114 

Pollution is an example of a negative externality, because the costs of pollution are borne 

by society as a whole rather than solely by the polluters themselves. In the case of pollution, 

there are various ways the government could intervene in markets to limit pollution to more 

economically efficient levels. One approach is to control pollution directly through regulation of 

polluters, such as by requiring coal burning electric utilities to install scrubbers to limit their 

emissions of various pollutants. Other more market oriented approaches to achieving socially 

optimal levels of pollution control are also possible. One such approach is to set a tax on the 

polluting activity that is equal to the social cost of the pollution. Thus, if burning a gallon of 

gasoline results in pollution that represents a cost to society as a whole of $1, it would be 

economically efficient to tax gasoline at $1 per gallon. By so doing, the externality is said to be 

internalized, because now the private polluter faces a private cost equal to the full social cost, 

and the socially optimal amount of consumption will take place. An alternative market-based 

approach to control pollution is to employ a system of payments, such as perhaps tax credits, to 

essentially pay polluters to reduce pollution. If the payments can be set in such a way as to yield 

the right amount of reduction (that is, without paying for reduction more than the reduction is 

valued, or failing to pay for a reduction where the payment would be less than the value of the 

pollution reduction), the socially desirable level of pollution will result. The basic difference 

between these two approaches is a question of who pays for the pollution reduction. The tax 

approach suggests that the right to clean air is paramount to the right to pollute, as polluters and 

those who buy goods and services from polluters would bear the social costs of their pollution. 

The alternative approach suggests that the pollution reduction costs should be borne by those 

who receive the benefit of the reduction. 

In the case of a positive externality, the appropriate economic policy would be to impose 

a negative tax (i.e., a tax preference) on the consumption or production that produces the positive 

externality. By the same logic as above, the externality becomes internalized, and the private 

benefits from consumption become equal to the social benefits, leading to the socially optimal 

level of consumption or production. An example where such a positive externality is thought to 

exist is in basic scientific research, as the social payoffs to such research are not fully captured 

by private parties that undertake, and incur the cost of, such research. As a result, a socially suboptimal level of such research is undertaken. The provision of a subsidy for such research can 

correct this market inefficiency and lead to socially optimal levels of research. 

Some have also argued that decreasing the dependence of the U.S. on foreign source 

energy is desirable for geopolitical and national defense reasons, and that this provides a 

rationale for subsidizing domestic fossil fuel production as well as subsidizing conservation and 

renewable energy production. However, in recent years there has been increasing focus in the 

tax code on energy conservation and renewable energy production incentives. The remainder of 

the discussion herein will focus on some considerations in the design of these incentives. 

Issues in the design and efficacy of tax expenditures for energy conservation and renewable 

energy production

Economists generally agree that the most efficient means of addressing pollution would 

be through a direct tax on the pollution-causing activities, rather than through the indirect 

approach of targeted tax credits for certain technologies. By the direct tax approach, the 

establishment of the economically efficient prices on pollutants, through taxes, would result in 
115 

the socially optimal level of pollution. To achieve this result, the tax would be set equal to the 

cost to society of the incremental pollution. The imposition of a direct tax on the pollutioncausing activity would indirectly lead to the adoption of the types of technologies favored in the 

tax code, but only if these technologies were in fact the most socially efficient technologies. A 

tax on the pollution causing activity is technologically neutral−a tax does not favor any particular 

technology that individuals might choose to utilize, or favor any particular behavioral 

modification that individuals may choose to make, in their pollution reducing responses to the 

tax. Rather, individuals would choose the most cost effective and economically efficient means 

of altering their behavior in response to the tax. For example, the optimal behavioral responses 

to a broad based tax on fossil fuels would lead to installation of greater amounts of home 

insulation, but would also lead to individuals turning down the thermostat or switching off 

unnecessary lighting. It would be difficult or impractical to design tax subsidies to directly 

incentivize the turning down of thermostats, the switching off of lights, or other similar forms of 

optimizing behavior. 

Nonetheless, many provisions of current law provide targeted tax credits for investment 

in, or expenditures on, certain assets that reduce, directly or indirectly, the consumption of 

conventional fuels and the attendant pollutants and emissions of gases related to atmospheric 

warming. The design of these tax benefits is important to how close they will come, individually 

and collectively, to achieving their intended objectives in a cost effective and efficient manner. 

Ideally, their design would be coordinated to try to mimic the more economically efficient 

outcome that a broad based tax would provide. 

The most important consideration in the efficient design of targeted subsidies is to 

determine what activities to subsidize and how much to subsidize them (i.e., what a credit rate 

should be, for example). In setting the policy parameters, the government is implicitly setting 

the price it will pay for the energy production or conservation that is produced or conserved in 

the manner specified by the tax provision. To be technologically neutral and economically 

efficient, the government should seek to set its policy parameters so that the implicit price it pays 

for the same good, say fossil fuel displacement (typically measured in millions of British thermal 

units,166 or “MMBtu’s”), is the same under each tax provision that has the same purpose. If it 

sets its policies in this manner, then only the most cost effective production of such fossil fuel 

MMBtu displacement will be subsidized. 

While the government’s policy parameters indicate the price it is willing to pay for fossil 

fuel MMBtu displacement at the margin, in practice it is difficult to know how much overall 

incremental fossil fuel displacement (pollution reduction) the government is buying in the 

aggregate with a given conservation or renewables production credit. The reason is that the 

government subsidy typically applies to “inframarginal” activity, or activity that would have 

occurred even in the absence of the credit, so for such activity the government incurs an expense 

in subsidizing it in order to induce others at the margin to engage in the tax-favored activity. For 

example, a credit exists for the purchase of certain energy efficient furnaces. If we assume the 

 166 A British thermal unit is the amount of heat required to raise the temperature of one pound of 

water 1 degree Fahrenheit. 
116 

credit were $500 and assume that the typical energy consumption from the efficient furnace as 

compared to an average furnace resulted in 1,000 MMBtu less fossil fuel consumption over its 

lifetime, then government has set the price of 50 cents for each MMBtu of displaced fossil fuel 

consumption to encourage the adoption of the more efficient furnace. However, many 

investments in the energy efficient furnaces might have taken place even in the absence of the 

credit, and thus the government pays, via the credit, for fossil fuel displacement that would have 

occurred anyway. If two million furnaces are sold (leading to a billion dollars in credits being 

claimed), but only 200,000 of these were sold as a direct result of the credit, then only one tenth 

(200,000 divided by 2 million) of the fossil fuel displacement from the energy efficient furnaces 

can be said to have occurred because of the credit. Thus, in this hypothetical example, the true 

budget cost of the aggregate incremental displaced fossil fuel consumption is 10 times the 

implicit government price at the margin, or $5, for each MMBtu of displaced fossil fuel 

consumption.167 Additionally, individuals who have purchased a more efficient furnace might 

choose to heat their home to a greater degree since it will cost less to do so, thus negating some 

of the initial fossil fuel displacement from the purchase of the more efficient furnace, and further 

inflating the cost to the government of a given amount of fossil fuel displacement.168

While the government can in theory establish an efficient set of subsidies for the 

activities it chooses to subsidize, in practice it cannot administratively identify and set up 

programs to subsidize every conceivable energy saving practice. Additionally, it is not possible 

to identify meritorious technologies not yet invented, and the government must continue to 

expand the class of credit-eligible activities if it wishes to minimize the economic distortions that 

come from favoring certain technologies through tax subsidies over other technologies that prove 

equally capable of achieving reductions in fossil fuel consumption. Furthermore, the investment 

in research to develop such new technologies might be constrained by the existence of tax 

subsidies for current technologies, as investors in such research run the political risk that their 

newly discovered technologies will not be granted any tax subsidies in order to compete 

favorably with subsidized technologies. 

Table 10 compares the implicit price that the government is willing to pay per MMBtu of 

fossil fuel displacement of selected tax subsidies. The differing amounts paid for a given amount 

of MMBtu show that the government’s policies are not coordinated to pay the same price for 

MMBtu displacement regardless of source, and thus at the margin the government pays more to 

purchase MMBtu displacement from certain activities over other activities, which is not 

 167 This type of budgetary inefficiency can sometimes be tempered by targeting the credit at 

investment or expenditures above a base amount. 

168 In the conservation literature, this phenomenon of greater energy efficiency leading to 

behavioral responses that tend to increase the use of the more energy efficient equipment has come to be 

termed the “rebound effect,” and has been estimated to reduce expected energy savings by up to 30 

percent in the case of space heating and automobiles (see Frank Gottron, “Energy Efficiency and the 

Rebound Effect: Does Increasing Efficiency Decrease Demand?,” Congressional Research Service report 

RS20981, July 2001.) 
117 

economically efficient.169 As noted above, it cannot be known from this information alone what 

the total budget cost of the aggregate incremental renewable production that occurs as a result of 

the credits, due to renewable production that would have occurred in the absence of the credits. 

If, as an example, half of the wind energy production would have occurred in any event, then the 

total federal revenue cost of achieving the incremental wind energy produced is twice that stated 

in the table, if one assumes that all wind energy produced receives the credit.170 

Table 10.−Comparison of Selected Energy Production Tax Credits 

Statutory credit amount 

in 2008 

Credit amount stated in dollars 

per million British thermal units 

(Btus) of heat energy 

Wind power 2.1 cents per kilowatt-hour $0.72 

Geothermal power 2.1 cents per kilowatt-hour $0.72 

Open-loop biomass 1 cent per kilowatt-hour $0.34 

Advanced nuclear power 1.8 cents per kilowatt-hour $0.61 

Ethanol 45 cents per gallon $5.92 

Biodiesel $1 per gallon $8.45 

Notes: 

 1 kilowatt-hour = 3,412 Btus 

 1 gallon of ethanol = 76,000 Btus (low heating value) 

 1 gallon of biodiesel = 118,296 Btus (low heating value) 

 (values taken from Energy Information Agency publications) 

One can also compute the implicit price that the government is willing to pay per MMBtu 

for the various provisions designed to encourage taxpayers to conserve energy. As an example, 

 169 This discussion assumes that the benefits across all types of alternative energy are equivalent, 

and assumed to be the displacement of a fossil fuel. In reality, different alternative energy sources might 

displace different types of fossil fuels, whose negative externalities may vary. Also, the production of 

certain renewables, such as solar or wind energy, may be more benign than the production of others, such 

as ethanol. Thus, depending on these other factors, varying credit rates could be economically efficient if 

there are differences across the renewable in the net benefits from each renewable and the fossil fuel it 

displaces. 

170 The sec. 45 electricity production credit is allowed only on the wind produced for the first ten 

years the facility is placed in service. If the existence of the credit induces a wind facility to be built that 

would not otherwise have been, and such a facility lasts for 20 years, then half of the wind produced from 

such facility does not receive any federal credit, and the true cost of the federal credit for that facility is 

half of what is shown on the table. 
118 

Table 11, below, computes the implicit price the government is willing to pay to conserve motor 

fuel (normalized to MMBtu to facilitate comparison to Table 10, above) in the case of three 

hybrid motor vehicles available for purchase in 2006 for which taxpayers could claim a tax 

credit. For each vehicle listed in Table 11 the EPA estimated fuel economy for the vehicle was 

compared to a comparable non-hybrid vehicle and the lifetime fuel saving was calculated (third 

column).171 The last column reports the estimated implicit price the government paid to 

conserve one million Btu by dividing the maximum eligible tax credit a taxpayer could claim on 

the hybrid motor vehicle by the amount of energy saved over the life of the vehicle. 

Table 11.− Estimated Tax Credit Per MMBtu Conserved by Purchase 

of Selected Hybrid Motor Vehicles

Vehicle Maximum Eligible 

Tax Credit 

Estimated Lifetime 

Fuel Saving 

Dollars of Tax Credit 

Per MMBtu 

2007 Toyota Camry 2.4 

L four-door sedan $2,600 39 barrels of oil $11.49 

2006 Honda Accord V6 

AT four-door sedan $1,300 34 barrels of oil $6.59 

2006 GMC Sierra 1500 

SL pickup four wheel 

drive pickup truck 

 $650 20 barrels of oil $5.80 

As was the case for the energy production tax credits reviewed in Table 10, Table 11 

shows that the credits for the purchase of hybrid motor vehicles were not coordinated to pay the 

same price of MMBtu displacement regardless of source, and thus at the margin the government 

would pay more to purchase MMBtu displacement from certain vehicles over other vehicles, 

which creates an inefficiency to the government’s tax expenditure. 

Similar calculations can be made for other tax preferences that are intended to encourage 

conservation or displace existing energy sources with more environmentally benign energy 

sources. However, many such calculations are sensitive to the geographic location of the 

taxpayer and the qualified energy property. The payoff in reduced energy consumption from 

additional insulation of a personal residence depends upon the climate in which the taxpayer 

resides and the amount of insulation initially in the residence. The tax credit available to 

taxpayers for additional insulation depends only upon the quantity of insulation and the price 

paid for the insulation, and the price of insulation does not vary widely across the nation. 

 171 The calculations were made by the Congressional Research Service. The comparison 

assumes both the hybrid motor vehicle and the comparable non-hybrid vehicle would have a life of 15 

and one quarter years. Miles driven were not assumed to be constant across the 15.25-year life of the 

vehicles, but rather varied with the age of the vehicle. The comparable non-hybrid vehicles were the 

2007 model Toyota Camry LE four-door sedan, the 2006 Honda Accord V6 EX four-door sedan, and the 

2006 GMC Sierra K 1500 four wheel drive pickup truck. 
119 

Therefore, the implicit price that the government is willing to pay per MMBtu conserved will 

vary with such factors as the location of the taxpayer and pre-existing levels of insulation. As a 

further example, consider the hypothetical installation of a 10-kilowatthour rated photovoltaic 

power system. The University of California Energy Institute estimates the installed cost of such 

a system at approximately $80,000.172 If, over the assumed 25-year life of such a system, it 

could garner eight hours of daylight for 365 days per year, it would produce 730,000 kilowatthours of electricity offsetting as much electricity produced from other sources. The present-law 

30-percent tax credit for the installation of such a system would imply that the government was 

willing to pay $9.64 per MMBtu of displaced electricity. However, if the same system were only 

to average five hours of sunlight per day, it would produce 456,250 kilowatt-hours of electricity. 

As the installed cost of the system does not vary, in this case the present-law 30-percent tax 

credit for the installation of the system would imply that the government was willing to pay 

$15.57 per MMBtu of displaced electricity. 

Alternative minimum tax, nonrefundability, and other constraints on tax expenditures

Another design issue that affects the efficacy of many tax credits is their restricted 

availability. Many tax credits have stipulated dollar limitations, are nonrefundable, or cannot be 

used to offset tax liability determined under the alternative minimum tax (“AMT”). If a credit 

designed to overcome an externality is capped, then after the cap is reached the marginal cost of 

further investment becomes equal to the market price again, which is presumed to be inefficient 

because of the externality. The impact of these limitations is to make the credit less valuable to 

those without sufficient tax liability to claim the full credit, for those subject to the AMT, or 

those who have reached any cap on the credit. Given the arguments outlined above as to the 

rationale for targeted tax credits, it is not economically efficient to limit their availability based 

on the tax status of a possible user of the credit. It can be argued that, if such social benefits exist 

and are best achieved through the tax system, the credit should be both refundable and available 

to AMT taxpayers. In some cases making the credits refundable may introduce compliance 

problems that would exceed the benefits from encouraging the targeted activities for the 

populations lacking sufficient tax liability to make use of the credit. With respect to the AMT, 

the rationale for the limitation is to protect the objective of the AMT, which is to insure that all 

taxpayers pay a minimum (determined by the AMT) amount of tax. Two differing policy goals 

thus come in conflict in this instance. Similarly, caps on the aggregate amount of a credit that a 

taxpayer may claim are presumably designed to limit the credit’s use out of some sense of 

fairness, but again, this conflicts with the goal of pollution reduction. 

 172 Severin Borenstein, “The Market Value and Cost of Solar Photovoltaic Electricity 

Production,” Center for the Study of Energy Markets Working Paper 176, University of California, 

Berkeley, January 2008.