For the second year in a row, President Obama has his tax sights set on the oil and gas industry. In the proposed fiscal 2011 budget submitted by the Obama Administration this past week, the President has included $36,500,000,000 (zeros included for emphasis) of oil and gas taxes.  For an analysis of the breakdown of these taxes, see Nick Snow’s article in Oil & Gas Journal.

The President continues to believe that a good way to grow our economy and spur job growth will be to cause businesses to send more money to the federal government than to spend it in the free enterprise system.  The tax increases for the oil and gas industry are the same as the ones I wrote about last March and include:

• Repeal of percentage depletion,
• Eliminate expensing of intangible drilling costs,
• Extend the amortization period for geoligical and geophysical costs,
• Repeal the domestic manufacturer’s deduction (only for oil and gas companies),
• Remove the exception to passive loss limitations for working interest owners in producing properties, and
• Repeal the enhanced oil recovery credit and the credit for production from marginal wells.

It seems to me these proposals will have the opposite of the President’s stated desired impact. These types of policies will most likely result in fewer jobs, reduced government revenue, a shift away from domestic production to foreign production, and more reliance of foreign sources of energy.

Due to the instability of the current economy, companies may find it increasingly difficult to begin production on oil and gas properties currently under lease. The deferral of production might result in the lessee’s requirement to make delay rental payments to lessors in accordance with their lease agreements. It is important to realize the tax implications to both the lessee and lessor of such payments.

Delay rental payments are amounts paid by the lessee for the right to defer development of properties under a lease. Generally, these payments will be treated like other carrying costs and capitalized as leasehold costs. Delay rentals cannot be expensed unless the lessee can establish that the leasehold was acquired for reasons other than development. A lessee’s failure to make the required delay rental payments usually results in the termination of the lease.  As a result, a loss due to worthlessness may be deducted in the year of the lease termination.

Upon receipt of delay rental payments, the lessor must recognize the payments as rental income. The payments are not subject to depletion since the amounts received are not based on the production of the property. This treatment is different than the receipt of a lease bonus payment which often qualifies as depletable income to the lessor.

Many leases were signed prior to the current economic downturn when prices were much higher.  As a result, many leases may not be drilled within the original lease term due to concerns about the economic viability of the lease at today’s prices, forcing a decision on the payment of delay rentals.

In these tough economic times where many are struggling for cash, states are not an exception. In order to aid them in meeting budgetary goals, some states are proposing the idea of imposing new oil and gas levies.

Pennsylvania and California are proposing increased severance taxes on oil and natural gas production in their states (5% and 9.9% proposed severance tax, respectively). Arkansas passed, and now has in effect, a tax increase on oil and gas production. Companies in these states warn that the new tax levies could lead to lost jobs and higher energy prices as they decide to relocate their business elsewhere.

Some states, such as Colorado and Montana, have already attempted to pass legislation to increase these taxes, but the bills have died in their state legislature due to “vote no” campaigns funded by the industry.  Although there is obviously significant opposition to the higher taxes, some industry insiders point out that the higher taxes may not greatly impact a company’s drilling locations. For instance, Alaska (which has the highest severance tax rate at 25%) has not seen a reduction in drilling activity.

As companies make decisions on where to drill, they should keep an eye on the relevant state legislature as rising severance taxes may impact the economic viability of their projects.

The proposed tax law changes for the energy industry contained in President Obama’s fiscal 2010 budget will have a major impact on U.S. energy producers if passed into law, and I don’t like what I see in these changes.

It appears this administration is attempting to increase the cost of production to the point that alternative energy sources become economic options. Unlike many in Washington, I expect the market to react with changes in behavior if these proposals are enacted. The results could force producers to move overseas or even force them out of business, as well as significantly increasing prices for consumers. Of course, this may be just what the President is hoping for.

Here are some of the more significant provisions for oil and gas producers and their impact.

Losing the tax deduction for IDC is a big deal since this generally represents the vast majority of the drilling costs for a well. By requiring these costs to be capitalized and spreading the deduction over a number of years through the cost depletion deduction, the result will be higher taxes and reduced net present value of cash flow on the properties.

The loss of percentage depletion is another direct tax increase. While this affects all interest holders, it will significantly impact royalty holders. Most royalty owners are only able to take percentage depletion because they have very little cost basis against which to compute cost depletion.

Another change to the depletion deduction is the explicit requirement to have a reserve report to support the cost depletion calculation. Since not all companies pay for a reserve report to be completed each year, this will require an additional cost in addition to the increased taxes due to the loss of percentage depletion.

The specific exclusion of oil and gas companies from the manufacturing deduction is simply done to raise money and will have the ancillary effect of slower economic growth.

Repealing the passive activity exception for working interests will mean that many holders of working interests will be required to treat the income and losses as passive. The net effect will be a deferral of the net deductions in many cases.

The repeal of the Marginal Well Tax Credit will remove the ability for many wells to be economically productive. Collectively, these wells represent about 20% of the nation’s oil and 12% of its gas. Many of these wells may end up abandoned.

Increasing the recovery period for geological and geophysical costs from 24 months to 7 years will increase the net present cost of exploration activity.

If you’ve got questions on any of the proposed changes or how they could impact your business, please contact us.

Assistance on this post provided by Emily Strong.

A tax partnership is a tool used in certain drilling arrangements to ensure that the working interest owner who bears the cost of drilling a well also gets the tax benefits related to those costs.

Consider the following example.  A working interest owner who doesn’t have the cash to drill and develop his property strikes a deal with a third party operator to fund all of the drilling costs in exchange for a working interest in the property.  Even though the operator will incur all of the costs to drill that well, he can only deduct IDC in proportion to his ultimate working interest percentage.  The remaining IDC is treated as additional leasehold cost and is depleted (deducted) over time.  As a result, tax deductions for IDC paid in one year are not realized for tax purposes until later years. 

Here’s where a tax partnership  can be a huge benefit to the operator.  By establishing a tax partnership and contributing all of the property and the costs of drilling and development to that partnership, all of the costs incurred (and resulting tax benefits) can be allocated to the operator regardless of the ultimate working interest percentages.

Using a tax partnership is not without its hassles.  The biggest headache is the administrative burden of accounting for the activity of the partnership and the requirement to file a federal partnership tax return each year.  Therefore, you should carefully consider the tax implications before deciding to use a tax partnership.

If you have questions about whether you might benefit from using a tax partnership, we can help.

 A windfall profits tax is an idea floated by many that would tax an industry based on income in a single year that is much higher than its previous years.  The idea became very popular in late 2008 when the price of a barrel of oil approached $150.  President Obama made a campaign promise to enact such a tax.  Many people continue to push the idea of a Windfall Profits Tax even though oil has since dropped below $40 a barrel as a method to stimulate the economy.  Lloyd Chapman makes this argument in his Huffington Post article.

 There are some new changes to the 2008 Partnership Tax Return (Form 1065) that could make taxpayers have to do some more digging and have us, preparers, asking a lot more questions.

Schedule B (Other Information) was previously a half-page, list of 12 “yes or no” questions whose repsonses could easily be carried forward from the prior year. The new Schedule B (still labeled Other Information) now spans a page and a half! This makes the Form 1065 five pages instead of four.

New reporting requirements ask that you state any corporation, partnership, or trust that “directly or indirectly owns more than 50% of the profit, loss or capital of the partnership”. A separate section asks about individuals or estates that “directly or indirectly owns more than 50% of the profit, loss or capital of the partnership”. The key word that I think definitely has to be focused on is INDIRECTLY; that word alone will require a taxpayer to do some mapping of ownership amongst its partners.

Another question in Schedule B asks about the partnerships ownership of other entities. It requires you list any corporation or partnership directly with at least 20% or own “directly or indirectly 50% or more of the voting power”. Again, the term “indirectly” pops out to makes us think a little harder beyond just the entity filing the return and its partners.

So, as information is beginning to be gathered and you prepare to file your return or have it filed by your trusted tax professional, do yourself (and them) a favor and get this new information together as well. If you want to review all the new questions and required information, check out the IRS website to view a copy of the form.

One of the common issues encountered in the setup of a drilling company is the handling of the economic deal of the partners in the drafting of the partnership agreement.

Many deals, especially those financed by investment funds, have a tiered or waterfall structure for allocating income and distributions.  It is normal for the partners who are putting the deal together and who will run the day-to-day operations to have a relatively small ownership percentage on the front end since most of the capital will come from an investment fund.

Over time, based on the entity’s performance and the increase in value of the enterprise, these “operations partners” may increase their ownership percentage in the income and profits of the partnership.  This will usually occur once certain return hurdles are met for the “investment partners.”  Unless provided for in the partnership agreement, this switch in sharing percentages will result in the “investment partners” being allocated more income and therefore more distributions over time that the parties intend.

Although there are several options, the best way to make sure all partners end up being allocated the income and distributions everyone intends each party to receive over time, is to handle income allocation and distribution provisions independently in the partnership agreement.

Like-kind Exchanges, or 1031 Exchanges, allow for the deferral of gain on trade or business or investment property when it is exchanged for similar property. Like-kind exchanges are often used by businesses to exchange cars or pieces of real estate. Similarly, you can use a 1031 Exchange for oil and gas properties as well.

Working interests and royalty interests are considered interests in real estate. As a result, not only can you exchange a working interest for another working interest and take advantage of deferring tax on the gain, you can exchange oil and gas interests with other types of real estate as well.

To qualify for Like-kind Exchange treatment, there are some limitations:

1. The property relinquished and the replacement property must be trade or business property or be property held for investment.
2. Upon the sale of the relinquished property, you have 45 days to specifically identify the replacement property. There are additional limitations if you identify more than three replacement properties.
3. You must close on the purchase of the replacement property within 180 days of the sale of the relinquished property.
4. The exchange must take place using a qualified intermediary.

For additional information on using 1031 Exchanges for oil and gas properties, see this article from 1031 Corporation.