Severance tax rates and long laterals lead energy discussion
The Oklahoman’s Adam Wilmoth and Paul Monies fielded questions this week from readers during their monthly energy chat. This is an abridged transcript of that conversation. For the full transcript, or to participate in next month’s chat, go to NewsOK. com.
Q: In light of the current huge deficit our state faces, would you support a roll back on the big tax breaks oil companies get to help ease the budget situation and help our state?
Paul Monies: That’s certainly been a point of discussion at the Capitol this year. First, a little background: Oklahoma lawmakers in 2014 “harmonized” the state’s taxing regime for severance, or gross production taxes. The law actually went into effect in July 2015. All new horizontal and vertical wells since then are taxed at 2 percent for 36 months, before rising to 7 percent. (The old rates were 1 percent for 48 months for horizontal wells, with vertical wells at 7 percent.)
The lower oil and natural gas prices, combined with a mix of rates going in since July 2015 have led to much lower collections from gross production taxes going to the state budget. Democrats at the Capitol have suggested raising the rates, and/or indexing the tax rate to the price of oil and gas. But there doesn’t seem much appetite among Republicans to make those changes. It’s complicated by the fact that an increase in the rate would likely require a ¾ majority in both the House and Senate. For its part, the industry says now is not the time to raise taxes on oil and gas producers, especially as the industry emerges from a severe
downturn and drilling activity is ramping up.
Adam Wilmoth: The big oil producers are pushing for the ability to drill horizontal wells as long as two miles in all rock formations as an economic benefit to the state. They say those wells would increase production for the companies, which would increase gross production taxes for the state and boost royalty payments to mineral owners throughout the state. Smaller oil producers are concerned about how long wells could hurt their existing production.
Q: How do you consider those tax “breaks” when it is an extra tax imposed on Gross revenue, separate from and in addition to income tax?
Monies: Oklahoma has taxed oil and gas for more than 100 years at various rates, so it’s not like it’s a new policy.
And yes, oil and gas producers are also subject to the corporate income tax, although like other corporations, they employ various strategies and incentives to lessen those tax burdens. And oil and gas itself is not taxed locally for property taxes. Only oil and gas equipment gets taxed at the local level. That's why so much of the gross production taxes are split into various state funds besides
the general revenue fund. County roads and bridges and education funds also get significant chunks of the gross production tax revenues.
Q: How realistic are legislators' fears that raising the gross production tax would upset the oil & gas industry? It seems Devon has a large tower, and Chesapeake has a substantial campus. Would those companies really leave such large real estate investments because of a gross production tax increase?
Wilmoth: I don't think they would close up shop and move out of town. But the industry associations have said the gross production tax rate is a factor when deciding where to put their drilling dollars. It is a factor along with the quality of the rock, access to infrastructure and other factors. The industry groups also have pointed out that each rig is like a small factory, employing 40 or so people who eat and shop in rural Oklahoma and boosting royalty revenue for people in the area.
Q: Is the only push back on the OCC (Oklahoma Corporation Commission Oil and Gas Division) on two-mile laterals in all rock formations from smaller operators?
And if so, what additional concerns are there from a two-mile standpoint that do not exist from a single-mile lateral?
Wilmoth: This is another example of how rapid changes in the industry have created challenges. A two-mile lateral produces roughly twice as much as a one-mile well for not much more cost, boosting the return on the well and making them economical where previously they would not be economical. The big producers say that in many cases, they will not drill one-mile wells, because they aren't worth the cost. So in some areas, a company could be drilling multiple wells in multiple depths from one well pad. Today, they can drill two-mile laterals in shale, but only one mile in other rock formations. So in some cases, they are drilling only in the shale and leaving the other rock formations alone. They say that if the law were changed, they would drill in all those layers, boosting production, revenues and royalties from the existing well pad.
The concern is from smaller producers who have vertical wells in the area. Those vertical wells are not producing from shale, so they don't care what happens to those rock layers. But they say large horizontal wells in their producing layers can hurt their existing wells. The small producers also are concerned that they can be forced out of their leases if large companies want to drill several multimillion dollar wells in the area. If the small producers can't afford to buy into all those wells, they could be forced to sell their positions.