A BIG INVESTMENT WITH BIG TAX BREAKS

(OIL AND GAS TAX PROVISIONS)


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I can understand where the oil company wants to deduct the cost of drilling a well. That's one of the tax breaks for oil companies - the subsidies - they get to deduct the cost of the well the year you drill.                                                                                                     -Rep. Dan Benishek
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STRIKING OIL

The main benefits of investing in oil include:

  • Intangible Drilling Costs: These include everything but the actual drilling equipment. Labor, chemicals, mud, grease and other miscellaneous items necessary for drilling are considered intangible. These expenses generally constitute 65-80% of the total cost of drilling a well and are 100% deductible in the year incurred. For example, if it costs $300,000 to drill a well, and if it was determined that 75% of that cost would be considered intangible, the investor would receive a current deduction of $225,000. Furthermore, it doesn’t matter whether the well actually produces or even strikes oil. As long as it starts to operate by March 31 of the following year, the deductions will be allowed.
  • Tangible Drilling Costs: Tangible costs pertain to the actual direct cost of the drilling equipment. These expenses are also 100% deductible but must be depreciated over seven years. Therefore, in the example above, the remaining $75,000 could be written off according to a seven-year schedule.
  • Active vs. Passive Income: The tax code specifies that a working interest (as opposed to a royalty interest) in an oil and gas well is not considered to be a passive activity. This means that all net losses are active income incurred in conjunction with well-head production and can be offset against other forms of income such as wages, interest and capital gains.
  • Small Producer Tax Exemptions: This is perhaps the most enticing tax break for small producers and investors. This incentive, which is commonly known as the “depletion allowance,” excludes from taxation 15% of all gross income from oil and gas wells. This special advantage is limited solely to small companies and investors. Any company that produces or refines more than 50,000 barrels of oil per day is ineligible. Entities that own more than 1,000 barrels of oil per day, or 6 million cubic feet of gas per day, are excluded as well.
  • Lease Costs: These include the purchase of lease and mineral rights, lease operating costs and all administrative, legal and accounting expenses. These expenses are 100% deductible in the year they are incurred.
  • Alternative Minimum Tax: All excess intangible drilling costs have been specifically exempted as a “preference item” on the alternative minimum tax return.

 

Developing Energy Infrastructure
This list of tax breaks effectively illustrates how serious the U.S. government is about developing the domestic energy infrastructure. Perhaps most telling is the fact that there are no income or net worth limitations of any kind for any of them other than what is listed above (i.e. the small producer limit). Therefore, even the wealthiest investors could invest directly in oil and gas and receive all of the benefits listed above, as long as they limit their ownership to 1,000 barrels of oil per day. No other investment category in America can compete with the smorgasbord of tax breaks that are available to the oil and gas industry.

  • Investment Options in Oil and Gas: Several different avenues are available for oil and gas investors. These can be broken down into four major categories: mutual funds, partnerships, royalty interests and working interests. Each has a different risk level and separate rules for taxation.
  • Mutual Funds: While this investment method contains the least amount of risk for the investor, it also does not provide any of the tax benefits listed above. Investors will pay tax on all dividends and capital gains, just as they would with other funds.
  • Partnerships: Several forms of partnerships can be used for oil and gas investments. Limited partnerships are the most common, as they limit the liability of the entire producing project to the amount of the partner’s investment. These are sold as securities and must be registered with the Securities and Exchange Commission (SEC). The tax incentives listed above are available on a pass-through basis. The partner will receive a Form K-1 each year detailing his or her share of the revenue and expenses.
  • Royalties: This is the compensation received by those who own the land where oil and gas wells are drilled. This income comes “off the top” of the gross revenue generated from the wells. Landowners typically receive anywhere from 12-20% of the gross production. (Obviously, owning land that contains oil and gas reserves can be extremely profitable.) Furthermore, landowners assume no liability of any kind relating to the leases or wells. However, landowners also are not eligible for any of the tax benefits enjoyed by those who own working or partnership interests. All royalty income is reportable on Schedule E of Form 1040.
  • Working Interests: This is by far the riskiest and most involved way to participate in an oil and gas investment. All income received in this form is reportable on Schedule C of the 1040. Although it is considered self-employment income and is subject to self-employment tax, most investors who participate in this capacity already have incomes that exceed the taxable wage base for Social Security. Working interests are not considered to be securities and therefore require no license to sell. This type of arrangement is similar to a general partnership in that each participant has unlimited liability. Working interests can quite often be bought and sold by a gentleman’s agreement.

 

Net Revenue Interest (NRI)
For any given project, regardless of how the income is ultimately distributed to the investors, production is broken down into gross and net revenue. Gross revenue is simply the number of barrels of oil or cubic feet of gas per day that are produced, while net revenue subtracts both the royalties paid to the landowners and the severance tax on minerals that is assessed by most states. The value of a royalty or working interest in a project is generally quantified as a multiple of the number of barrels of oil or cubic feet of gas produced each day. For example, if a project is producing 10 barrels of oil per day and the going market rate is $35,000 per barrel (this number varies constantly according to a variety of factors), then the wholesale cost of the project will be $350,000.

Now assume that the price of oil is $60 a barrel, severance taxes are 7.5% and the net revenue interest (the working interest percentage received after royalties have been paid) is 80%. The wells are currently pumping out 10 barrels of oil per day, which comes to $600 per day of gross production. Multiply this by 30 days (the number usually used to compute monthly production), and the project is posting gross revenue of $18,000 per month. Then, to compute net revenue, we subtract 20% of $18,000, which brings us to $14,400.

Then the severance tax is paid, which will be 7.5% of $14,400. (Landowners must pay this tax on their royalty income as well.) This brings the net revenue to about $13,320 per month, or about $159,840 per year. But all operating expenses plus any additional drilling costs must be paid out of this income as well. As a result, the project owner may only receive $125,000 in income from the project per year, assuming no new wells are drilled. Of course, if new wells are drilled, they will provide a substantial tax deduction plus (hopefully) additional production for the project.

The Bottom Line
From a tax perspective, oil and gas investments have never looked better. Of course, they are not suitable for everyone, as drilling for oil and gas can be a risky proposition. Therefore, the SEC requires that investors for many oil and gas partnerships be accredited, which means that they meet certain income and net worth requirements. But for those who qualify, participation in an independent oil and gas project can give them just what they’re looking for.

Start Making Better Investment Decisions
Today’s markets are filled with opportunities, but investors need to be smart. Call Arrow's Partner Relations line at (214) 299-7357 to help you review your goals.

For More Tax Information from the IRS see: IRS Oil and Gas Handbook and/or IRS Publication 535 (Deductible taxes).


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Intangible Drilling and Development Costs (IDC) – IDC tax treatment is designed to attract capital to the high risk business of natural gas and oil production. IDC generally include any cost incurred that has no salvage value and is necessary for the drilling of wells or the preparation of wells for the production of natural gas or oil.

  • 1913 – IDC considered deductible in the year incurred
  • 1976 – IDC considered as a tax preference item and subjected to minimum tax
  • 1986 – Integrated companies required to capitalize 30% of IDC over 60 month period; “excess” IDC considered as a tax preference item under the AMT
  • 1992 – Independent Producers and Royalty Owners (IPRO) may eliminate all or part of IDC as a tax preference item
     

Percentage Depletion – All natural resources minerals are eligible for a percentage depletion income tax deduction. Percentage depletion for natural gas and oil has been in the tax code since 1926. Unlike percentage depletion for all other resources, natural gas and oil percentage depletion is highly limited.

  • 1913 – Cost depletion allowed but did not reflect drilling risks
  • 1918 – “Discovery Value” depletion created but was too complicated to value
  • 1926 – Percentage depletion created to encourage drilling; set at 27.5% for natural gas and oil; limited to 50% of net income of property
  • 1969 – Percentage depletion reduced to 22%
  • 1975 – Percentage depletion repealed for natural gas and oil except for IPRO; limited to first 1000 B/D and capped at 65% of net taxable income; set at 15% and made not transferrable if the property were transferred
  • 1986 – “Excess” percentage depletion treated as a tax preference item under the AMT
  • 1990 – Percentage depletion allowed to be transferrable; percentage depletion allowed to increase above 15% for marginal wells as prices fall (maximum 25% at a $10/B reference price; property net income limitation increased to 100%)
  • 1991 – Excess percentage depletion no longer treated as a tax preference item under the AMT
  • 1997 – Percentage depletion property net income limitation suspended for marginal wells through1999
  • 1999 – Percentage depletion property net income limitation suspended for marginal wells through 200
  • 2002 – Percentage depletion property net income limitation suspended for marginal wells through 2003
  • 2004 – Percentage depletion property net income limitation suspended for marginal wells through 2005
  • 2006 – Percentage depletion property net income limitation suspended for marginal wells through 2007
  • 2008 – Percentage depletion property net income limitation suspended for marginal wells during 2009
     

Geological and Geophysical (G&G) Expenditures – G&G costs are associated with developing new American natural gas and oil resources.

  • 1913 – G&G expenditures considered deductible in the year incurred
  • 1942 – IRS instructions begin drawing distinctions on G&G expenditures between those related to those related to the acquisition/retention of properties (treated as capital expenditures) and those that did not (treated as deductible)
  • 1946 – Tax Court ruling supports IRS
  • 1950 – IRS issues ruling that G&G related to property acquisition/retention are capital expenditures; G&G that does not lead to property acquisition/retention are deductible
  • 1983 – IRS ruling provides more detailed guidance
  • 2005 – Congress amends tax code to set G&G amortization for all cases at 24 months
  • 2006 – Congress modifies G&G amortization for largest integrated oil companies to 5 years
  • 2007 – Congress modifies G&G amortization for largest integrated oil companies to 7 years
     

Enhanced Oil Recovery (EOR) Tax Credit – The EOR credit is designed to encourage oil production using costly technologies that are required after a well passes through its initial phase of production.

  • 1990 – Congress creates EOR tax credit of 15 % of EOR costs; credit has a phase out as oil prices increase; tertiary recovery technologies available for the credit defined by regulation (includes CO2 injection)

 

Marginal Well Tax Credit – This countercyclical tax credit was recommended by the National Petroleum Council in 1994 to create a safety net for marginal wells during periods of low prices.

  • 1994 – National Petroleum Council Marginal Wells report recommends creating a countercyclical tax credit as a safety net to support marginal wells during periods of low commodity prices
  • 2004 – Congress creates countercyclical marginal wells tax credit

 

Passive Loss Exclusion for Working Interests – Congress provided this distinction to encourage investment in American natural gas and oil production

  • 1986 – Congress creates division of investment income/expense into two baskets – active and passive. The Act exempted working interests in natural gas and oil from being part of the passive income basket and, if a loss resulted, it was deemed to be an active loss that could be used to offset active income as long as the investor’s liabilities were not limited.

 

Manufacturers’ Tax Deduction – Congress enacted this provision to encourage the development of American jobs.

  • 2004 – Congress creates the Section 199 tax deduction for American manufacturing; deduction begins at 3 % growing to 6 % and stops at 9 %; deduction limited to 50 % of U.S. W2 payroll
  • 2008 – Congress limits the Section 199 tax deduction of the oil and natural gas industry to 6 % (capped at 50 % of W2 payroll)