Texas Oil and Gas Attorney Blog

A study entitled “Impacts of Delaying IDC Deductibility” was published recently by Wood Mackenzie Consulting and was commissioned by the American Petroleum Institute (API) to estimate the effects of an Obama proposal to eliminate federal tax deduction of intangible drilling costs used by the oil and gas industry and to instead require that these costs be treated as a capital expense. You can read the entire study here.

The difference between a deduction and a capital expense is huge. A deduction allows you to use the entire amount of the deduction in the year it was incurred. If these costs are treated as capital expenses, only a small portion of the total can be deducted each year over the useful life of the relevant asset. Intangible drilling costs are currently deductible like other operating costs and the deduction allows oil companies to use that saved money immediately for other projects. Intangible drilling costs include costs like wages, fuel and repairs, and accounts for 60% to 90% of costs for a given oil or gas well. Most industries deduct expenses like these in the year they were incurred. The Obama administration, however, wants to single out the energy industry for special treatment (again).

The study looks at the impact if this proposal was effective January 1, 2014. The study estimates that in the first year alone, elimination of the intangible drilling cost deduction would result in the loss of 190,000 US jobs. By 2019, the study estimates 233,000 job losses. Energy investment would be expected to drop by almost $40 billion per year between next year and 2023, for a total investment loss of $407 billion. U.S. oil production would drop by 520,000 barrels per day in the first year and 3.81 million barrels per day by 2023. There would also be 8,100 fewer wells drilled by 2019 and 9,800 fewer by 2023, contributing significantly to the drop in productivity. The study finds that some smaller companies may not be able to invest in drilling and development at all if the change were to take place.

In Texas, and in much of the rest of the country, an oil and gas lease makes use of several different kinds of pipelines. When you are the recipient of a request for a pipeline easement, the kind of pipeline to be installed in that easement makes a night and day difference in how you negotiate the easement.

I recently spoke at a National Business Institute telephone seminar about the negotiation of pipeline easements. NBI provides “on-demand” CLE for attorneys and they have many excellent seminars on a wide variety of legal topics. You can access the audio of the seminar here, or you can register to take the seminar for CLE credit here.

The word “pipeline” can mean a variety of things, because there are several different types of pipelines. First, there are flow lines, which are lines from the well to other equipment on the well site, such as a tank or a heater-treater. Flow lines are located entirely within the well site area. The authorization for these lines is generally contained within the oil and gas lease itself. These lines are not regulated by either federal or state agencies.

In 2008, the Texas Supreme Court heard a class action case against Phillips Petroleum Co. The case was Bowden v. Phillips Petroleum Co., in which the Plaintiffs alleged that Phillips had underpaid their oil and gas royalties. The Supreme Court remanded part of the case back to the trial court.

When the case was remanded, the representative of the class, Royce Yarbrough, amended the complaint against Phillips to allege that the company breached their implied covenant to market and that this is what contributed to the underpayment of royalties to the royalty owners. Phillips argued that to add a new claim on behalf of the class required a new class certification motion and hearing. The trial court disagreed and Phillips Petroleum appealed. The Texas Supreme Court considered this issue in Phillips Petroleum Co v. Yarbrough, et al.

The Supreme Court actually reviewed several issues, including res judicata issues from the Bowden case and whether they had jurisdiction over the interlocutory appeal on the decision by the trial court regarding the implied covenant to market. But the most interesting issue for oil and gas lawyers in Texas concerns the substantive issue of implied covenants to market vis-a-vis express covenants to market.

Recently the Supreme Court of Texas issued a decision that is important for Texas surface owners and mineral owners and the Texas oil and gas attorneys who represent them. The case is Homer Merriman v. XTO Energy Inc. I discussed the background of the Supreme Court decision previously, and you can access that article here.

Background:

As you may recall, Homer Merriman bought a piece of land in 1996, but he bought only the surface rights, and the deed clearly reserved the minerals. XTO Energy Inc. had previously leased the mineral rights. Mr. Merriman used the land for his cattle business and used the particular tract in question to sort his cattle, with stock panels and electrical fences which he testified were not permanent fixtures. In 2007, XTO wanted to drill a well on this tract, and offered Mr. Merriman $10,000 in compensation for this use, but he refused and the case went to court.

Texas royalty owners should get to know the website, FracFocus. This website provides a list of chemicals and other ingredients in fluids used by oil and gas well operators for hydraulic fracturing of wells both in Texas and across the country. The intent of the website is to allow the public to access this information and to provide objective and accurate data about hydraulic fracturing. FracFocus is managed by the Ground Water Protection Council and the Interstate Oil and Gas Compact Commission.

Twelve states currently require operators to report their data on FracFocus and eight more states are about to require reporting. The website currently has more than 45,000 records from more than 400 companies.

A new version of the website went online on June 1, 2013 that promises to be even easier to use according to witnesses who testified before the U.S. Senate Energy and Natural Resources Committee during their first natural gas forum. Some of the changes in the new version of the website include the display of data in a format that is easier to aggregate and customize. In addition, the new website will allow a search by the name of a chemical, using the Chemical Abstracts Service number, and a date range.

In April 2013. representatives in the US House of Representatives announced that bipartisan legislation would be introduced in 2014 to take out corn based ethanol requirements in the federal Renewable Fuel Standard

The bill is called the Renewable Fuel Standard Reform Act. Those involved in the oil and gas industry know that the standards involving ethanol can effect the market by conferring an artificial advantage for the so called “renewable” fuels over oil and gas.

The current Renewable Fuel Standard requires 36 billion gallons of renewable fuels to be included in the domestic fuel supply by 2022, and almost all of that is from corn-based ethanol. This requirement uses a massive percentage of America’s corn supply and diverts it to fuel. In 2011, 40% of the nation’s corn went to making ethanol, which is about five billion bushels of corn. Because so much of the corn crop is used for ethanol, there is less for food and for livestock feed. The end result is a substantial increase in the price of corn and everything that has corn as an ingredient, hurting consumers and many small businesses. In addition, ethanol in fuel wrecks havoc on everything from car engines, to lawnmowers to chainsaws. No one has bothered yet to assign a cost for these damages to consumers.