Too Good to Be True? Unique Tax Aspects of the Oil and Gas Industry

Would you be excited as an investor if you had the chance to invest a sum of money late in the tax year and yet deduct almost your entire investment as a business expense in the year you invested? Not only that, but the deduction would offset your other self-employed income for self-employment (SE) tax purposes. Better still, the deduction/loss would not be limited as a passive loss. Finally, when the business investment begins to payoff, the resulting income is subject only to regular income tax and is not considered self-employment income. This “have your cake and eat it too” result can be accomplished with the right type of investment and proper planning. Such an opportunity exists in the oil and gas industry.

 

The appeal to an operator planning to drill for oil or gas is that he can offer potential investors significant tax benefits along with the opportunity to share in the actual results of the exploration and production activity. This could be the deciding factor when the potential investors are deciding where to put their money.

 

The Internal Revenue Code (IRC) provides several incentives to the oil and gas industry to encourage investment in and development of oil and gas exploration activities. One of the more significant incentives is the ability for investors to deduct the portion of the costs incurred in the drilling operation that are deemed intangible drilling costs (IDC). There are, however, certain requirements that must be met for the taxpayer to be able to claim the IDC deduction.

 

Requirements to Claim IDC Deductions

First, since IDCs are paid for by working interest owners, it goes without saying that the investor must have a working interest in the property. Sole proprietors, participants in joint ventures, partners in partnerships and shareholders in subchapter S corporations are deemed to own their respective shares of whatever assets are owned by the entity. Therefore, working interests held by one of these entities would be considered to be owned in part by the investors. This is in contrast to shareholders in regular C corporations who are not considered to own a share of the entity’s assets. As a result of being considered the owner of a working interest you are deemed to be engaging in a trade or business. This means those losses/deductions can offset other SE income currently.

 

Second, the taxpayer must be considered an active participant in the venture to be able to avoid running afoul of the passive activity rules of IRC Section 467. Those rules generally restrict a taxpayer’s ability to deduct losses from activities that he is not actively participating in. Active participation usually requires a taxpayer to spend a significant amount of time in the activity and/or take part in significant operating decisions. This is normally a major problem for most investors since they lack the time and/or talent required to be classified as active participants. Luckily, IRC Section 469(c)(3)(A) states that when a taxpayer holds a working interest either directly or indirectly through an entity that doesn’t limit his liabilities with respect to that interest, the activity will not be considered passive and the related losses/deductions will not be limited by these rules. It is important to note that the requirement that the taxpayer’s liability not be limited eliminates the use of subchapter S corporations, limited partnerships and limited liability companies. For the most part, this means you would want to structure it as either a joint venture (electing to be taxed as a partnership) or a general partnership.

 

Expenses, Timing and Taxes

So to this point, you have carefully chosen to conduct this operation as either a joint venture or general partnership. The general rule for income tax reporting purposes is that expenses are deducted only when economic performance has occurred. This usually means that you may only deduct the costs for events that have already happened in the tax year. This would seem to be a problem when the investors put up money late in the tax year. How can you drill all the wells you raised money for in only a month or two before the end of the current year? The answer hinges on another unique aspect of the oil and gas industry.

 

IRC Section 461(i)(2)(A) provides a solution to this timing problem. It states that amounts paid for IDC during the tax year are treated as deductible in the current year as long as actual drilling begins within the first 90 days of the following year. This means that when you pay a third party for drilling a well in year one and the actual drilling is begun by the ninetieth day of year two, that amount of drilling costs will be deductible in year one.

 

Having established that the taxpayer can make an investment late in the year, get a current year deduction which offsets both regular tax and self-employment tax and those losses will not be limited by the passive activity rules, it only remains to be seen how future net income can be earned and not be subject to SE tax.

 

If the operation continues to operate as a joint venture or general partnership, the income earned will be taxed as ordinary income and will be subject to the SE tax as well. The final step necessary to achieve all the tax benefits mentioned involves taking advantage of the fact that the owners in a joint venture can choose to form a limited partnership at any time to conduct future business. Similarly, general partners can choose at any time to convert from a general partnership to a limited partnership (“LP”) with no adverse tax consequences. Once it is determined that there will be no further significant expenditures for IDC, the formation or conversion of an LP can take place. Earnings of the investor after the conversion to an LP will be excluded from future SE tax calculations under IRC Code 1402(a)(13).

 

There are numerous issues to consider before adopting this type of structure that are not addressed here. This article is intended merely to demonstrate that proper planning can make major differences in outcomes when it comes to income taxation of oil and gas operations.

 

North Dakota crude breakeven prices as low as $24/b: state agency

Washington (Platts)–27 Jul 2015 512 pm EDT/2112 GMT

US crude prices would still need to drop significantly before falling below breakeven prices in North Dakota’s four most prolific counties, according to data released by the state Department of Mineral Resources Monday.

Breakeven prices for rigs in North Dakota’s Dunn, McKenzie, Mountrail and Williams counties range from $24/b in Dunn to $41/b in Mountrail, according to the data.

Those four counties accounted for 63 of the state’s 68 oil rigs on Monday, according to the data.

The breakeven prices ranged from $28/b to $42/b in the four counties when the DMR published its last such data in October 2014.

At the same time, breakeven prices have fallen dramatically in counties with far less drilling activity, the data shows. The breakeven price is $62/b in Divide County, which has three working rigs. Previously, the breakeven price in Divide was seen to be $85/b, when the county had eight working rigs. McLean County saw its breakeven price fall to $25/b from $73/b, although there are no longer any working rigs there, according to the data.

The drop in breakeven prices comes as North Dakota’s crude production has grown as rig counts and prices have dropped. Earlier in July, the state’s oil and gas regulator reported that crude production topped 1.2 million b/d in May, compared with April production of less than 1.17 million b/d and just shy of the all-time record of 1.23 million b/d, set in December 2014.

This production boost, aided by improved drilling technology and increased efficiencies, came as the statewide rig count in May fell to 83. The all-time of 218 was posted in May 2012.

Read More: PLATTS – McGraw Hill Financial

Oil woes? Not in North Dakota

An earlier version of this story incorrectly stated North Dakota’s recently-set monthly record for natural gas production. The state produced 1.6 billion cubic feet a day in June.

North Dakota is holding its own when it comes to producing oil, despite the stubborn slump in oil prices and predictions that the U.S. shale boom is about to fade.

635751701514370768-ThinkstockPhotos-152955115-1-A new report from North Dakota’s Department of Mineral Resources puts the state’s oil output at 1.21 million barrels a day in June, its second-highest monthly rate ever. North Dakota also set a monthly record for natural gas production, with 1.6 billion cubic feet in June.

“What we’re observing is U.S. producers are not indicating any decrease in U.S. oil production,” Lynn Helms, the director of the state agency, told reporters Friday. “Even if the price has dropped, they are finding ways to cut costs and to be a lot more efficient with their drilling and completions, and they’ve built up a very large number of non-completed wells.”

That said, production from North Dakota’s resource-rich Bakken shale has slowed considerably lately, with just 8,600 barrels added in June — which averaged 1.21 million barrels a day — compared to May, according to the state’s numbers.

But with 848 wells drilled but not yet producing, and a “relatively stable” drilling-rig count lately, Helms doesn’t expect production to decline.

“The capacity is there to maintain North Dakota production for a whole two years, even at these sustained low prices,” he said.

So what does Helms make of widely held views that OPEC, especially Saudi Arabia, is producing at higher-than-usual levels to drive down prices and squeeze out U.S. shale oil producers? Not much.

“Even though we have the low prices, we’re not seeing the drop in production that some people thought OPEC was trying to achieve,” he said. “It would appear that OPEC’s efforts are geared more toward other competitors, like Russia and Iran.”

Similarly, Helms takes a dim view of reports from OPEC, the U.S. Energy Information Administration and other energy-market analysts that low oil prices will force U.S. oil production to taper off later this year and in 2016.

“I think there’s some conflict there,” he said. “EIA as well as OPEC have consistently underestimated the resiliency of the North American shale plays. Most of the decline they’ve projected is supposed to come from the Permian and Eagle Ford (shale basins), not from the Bakken.”

But the Permian and Eagle Ford basins, both in Texas, have as many or more non-completed wells than the Bakken — wells that have already been drilled but not yet hydraulically fractured to produce oil.

“It’s going to be very resistant to declining prices, production, that is,” Helms said.

Helms’ remarks on Friday came as West Texas Intermediate, the U.S. benchmark for crude, fell below $42 a barrel for the first time in more than six years. WTI finished the day at $42.50.

EIA forecasts that global oil prices will average $54 a barrel in 2015 and $59 in 2016, and U.S. prices will average $5 a barrel less in each of those years.

North Dakota oil production typically sells at a discount to WTI because of the state’s remote location and the cost of shipping crude to markets for refining. Despite that difference, the break-even price for Bakken production is under $30 a barrel in some places.

Thanks to horizontal drilling and hydraulic fracturing techniques in the Bakken shale, North Dakota’s production has soared in recent years, making it the second-largest oil-producing state in the U.S. Only Texas pumps more oil.

One “game-changer” for producers in North Dakota as well as in other states would be a U.S. government decision to allow exports of U.S. crude, a move that could add $8 to $10 to the price of a barrel of oil, according to Helms.

“The U.S. refineries that prefer light sweet crude oil have basically all they need,” he said. “So, the market expansion is overseas. There’s a lot of pressure to allow U.S. oil to be exported.”

The Senate and House are both considering legislation that would lift government restrictions on U.S. oil exports, which were enacted in 1974, amid oil shortages and gasoline lines. While U.S. producers are pushing for such action in Washington, some refiners prefer to keep U.S. oil in the country to keep crude prices down.

Meanwhile, given the state of oil markets, North Dakota is doing rather well.

Bill Loveless — @bill_loveless on Twitter — is a veteran energy journalist and television commentator in Washington. He is a former host of the TV program Platts Energy Week.

Read More: USA Today

Good Production, Prices Concentrate in Four North Dakota Counties

The continued strong production and favorable breakeven prices for North Dakota’s Bakken Shale play are concentrated in four counties where the vast majority of the state’s greatly reduced number of drilling rigs are still operating, the latest county-by-county statistics show.

Out of 14 counties in which oil/gas production is ongoing, the vast majority of the production comes from Dunn, McKenzie, Mountrail and Williams counties, all of which are enjoying the lowest breakeven prices available in today’s globally depressed commodity prices, the state Department of Mineral Resources (DMR) reported earlier this week.

North-Dakota-Drillings-Rigs-by-County-20150820McKenzie County has more than one-third of the rigs still operating in the Bakken (26) and a breakeven price of $27/bbl, compared to a $29/bbl breakeven price and 58 active rigs in January. “The breakevens are so low in McKenzie because a typical well has an initial production rate [IP] of more than 3,000 b/d, and they are also high gas producers,” said DMR Director Lynn Helms.

The combination of high IP rates and “a very robust” gas revenue stream keeps the economics in McKenzie favorable for continued production, he said. “That drives some of those breakeven costs way down.”

The other factor is efficiency gains by the operators in driving down well costs, which Helms said has had an “enormous” impact on keeping North Dakota oil production at around 1.2 million b/d. “Well costs are down about 22% and they are continuing to drop,” he said, adding that operators have found ways to use fewer trucks; they can cover more wells with walking rigs; and rig counts could drop into the 50s with all of the efficiencies. The current count is 74 rigs operating.

Besides McKenzie the other three very productive counties have similar situations, with Dunn supporting 11 rigs and a $24/bbl breakeven price; Mountrail has 13 rigs and a $43/bbl breakeven; and Williams has 16 rigs and a $38/bbl breakeven, according to the latest DMR statistics. In January, the threesome had 23, 28 and 32 rigs in operation, respectively.

DMR officials said they developed the county-by-county breakeven prices by tracking economic data submitted by operators during monthly hearings. “We have an economic data set that includes monthly well operating costs, yearly drilling costs and IP rates for each county for the past 12 months and type curves to model average well production by county,” a DMR spokesperson said.

Using this data, DMR calculates the county breakeven prices at a 10% rate of return for the operators. Last November, there were 188 rigs operating in the state, and 169 of them were in one of the four big producing counties with McKenzie heading the list with 72. Breakeven prices were a little higher, ranging from $29/bbl in Dunn to $45/bbl in Mountrail.