Michael Filloon: Are North Dakota's Oil Taxes Too High?
North Dakota oil production taxes have seen significant debate recently. It wasn’t the tax rate in general, but the tax trigger, which afforded oil producers a 45% tax break. This trigger was recently replaced by a much less complicated system that varies only 2% depending on oil prices.
Although the trigger was removed, it is still in effect for 2015, so it is possible we could still see oil producers get a $1 billion tax break. The chances have declined significantly. The rise in the Euro has weakened the dollar and allowed for crude price inflation. This is great for the state, and we hope the average price for WTI (West Texas Intermediate) remains above $55.09/bbl in May. The truth is, currency and commodity speculators should be thanked. When both the Euro and WTI bottomed we saw significant short covering.
Although this is a complex process, the essence is speculators had to buy oil and Euros because they were losing money when both started heading higher. By buying, it offsets losses incurred when prices increase. This caused the big move as little has changed for oil, and we may be in a long term low price environment for Bakken crude.
The main issue with speculators is their manipulation of the market. Although we usually hear about how speculators move markets lower, it can be more dangerous when prices are pushed higher. An investor could think the oil markets are in good condition because oil prices have recovered and buy high risk investments. Short term speculators pull large positions, and the everyday investor watches his or her investment decrease significantly in value.
An investor could have the right investment thesis, and still get washed out by dollars pushing the market around. I’m not saying this to scare anyone, but when the world produces too much oil, it usually takes longer for prices to recover. The Bakken is fine, but will have to adjust in the short term. Usually, oil prices decrease because of decreased demand. Low prices naturally spur demand through lower fuel costs. When consumers pay less at the pump, they have more disposable income. This is then spent on consumer discretionary items as well as staple and more gasoline.
By increasing the amount of money in everyone’s pockets, economies can recover and demand picks up.
In this case, we have too much supply. This means every time we see an uptick in demand, operators will increase production and push the price of oil back down.
It is anyone’s guess where oil prices will head from here, and each price recovery is very different. Most analysts believe this recovery will be more like 1986 or 2000-2001. It is possible this could be even slower, as we have never went from a tight supply market to a significant oversupply.
Hopefully we will see OPEC and non-OPEC producers find a common ground, but this is a difficult proposition. OPEC will continue to fight to add customers and protect its current market share. Production is also increasing quickly, as countries like Saudi Arabia and Iraq will produce more oil to increase revenues.
he current situation is tough, as oil inventories are at 80 year highs. Total US storage is 93% full and we need a drawdown during driving season. If not we may have trouble storing the addition oil in the fall. The issue will be refinery downtime. Refineries run at a lower throughput when it prepares to produce winter blends of fuel. Because of this fewer crude barrels are refined or “cracked”, and could add to an already full storage.
Several things need to happen for this not to occur. The first would be a pick-up in global demand for refined products. This is possible but numbers have been poor from Europe, Japan or China. All three areas are doing stimulus and/or QE (quantitative easing). If these programs work, demand could improve but it may take time. Another possible catalyst is a decrease in world production. The problem is OPEC as production from Iraq and Saudi Arabia continues to increase. Iran is an issue with approximately 28 million barrels of crude on ships ready to deliver if a nuclear deal is reached.
It is possible that OPEC thinks creating a global glut of crude will deter future development in non-OPEC nations. This may not only affect the US, but other countries with higher production costs. US production hasn’t been affected. Last week production was 9.374 million barrels compared to 9.369 million barrels the week prior. This is a 13.7% increase in production year over year. Rig numbers are down, but 5000 locations (fraclog) have been drilled and not completed. The rigs aren’t needed to increase production.
Operators only need to add frac crews. Plus operators are high-grading, or developing the best areas. Each location produces more resource so half the wells are needed to maintain production levels. Production may head lower, but this may not be significant enough to affect US inventories. Gasoline and Distillate inventories are also headed higher. The last variable is the Euro. It is up significantly, as there are worries a rate hike won’t occur in 2015.
Although the Fed is not highly motivated to raise rates, it will still need to in the near future. Most economists believe the hike will occur in September. Since Europe’s QE program is just beginning, the combination of the two should be positive for the dollar.
These are all reasons most analysts (including Goldman Sacs) believe oil will pull back in the second or third quarter. If this occurs, oil prices should find a floor and begin to trade up through year end. The question is where oil prices are headed and why? Quarterly earnings reports produced significant data on the subject. Pioneer’s (PXD) Permian acreage in Texas has some of the lowest well costs in the country, and is planning to add 2 rigs in July. Breakeven costs are just $40/bbl in the best areas, providing a Permian advantage. Whiting (WLL), Continental (CLR), Occidental (OXY) and EOG Resources (EOG) all plan to add rigs at $70/bbl oil.
The focus is on the fraclog. Rig numbers may remain low without affecting production as there are wells to complete. We already saw a production increase in March from the Bakken. It increased 15,000 bbls/day over February. Although EOG Resources and Marathon (MRO) continue to delay fraccing others have continued to drive cash flows. The bigger players like Exxon (XOM), Conoco (COP), Hess (HES) and Continental (CLR) are working through fraclog at a quicker pace. Production increases at $70/bbl will put downward pressure on oil prices. This means more oil will hit the market, and push oil prices lower. It is possible the fourth quarter trading range may be $65 to $75/bbl. Oil prices may rise in 2016, but it is too early to tell.
Costs are down 20% to 30% year over year. Production has also increased 30%. This combination has pushed down breakeven prices per barrel. A current well at $60/bbl is producing the same economics as a well two years ago at $90/bbl. These types of improvements are fantastic, and due to new completion techniques. These are the reasons the Bakken will continue to do well. The economics of just a few years ago would not be good enough to support development, even in the best areas.
Now, much of the core play is still excellent even at $60/bbl oil. As an example, we can look at average results from QEP Resources (QEP). Its acreage is in northeast McKenzie County and is in the core of the Three Forks play. The middle Bakken is excellent as well, but this area has the best overall production from both plays in concert. This basically means that not only can 8 great wells come from the Bakken but another 8 from the upper Three Forks.
In just 120 days, these wells produce 160 MBoe. They produce approximately 78% oil, 11% NGLs, and 11% natural gas. Using $60/bbl oil, $23/bbl NGLs, and the barrel equivalent of $17/bbl of natural gas we see excellent results. Over the first 120 days, $8,192,000 in revenues are produced. This compares to the $9 million in well costs. What this means, is QEP gets paid back in less than 5 months. Keep in mind, most operators would like a 12 month payback, and would settle for 18.
This is not a typical area, but it doesn’t have to be. There are many prospects in the Bakken and other plays that have these types of economics. Operators would like a plus-$60/bbl scenario, but it’s not necessary to keep drilling wells. Those predicting the demise of oil production in North Dakota are mistaken, as it will continue to produce at a steady rate for some time.
The recent changes to production taxes should benefit North Dakota due to the new oil price environment. The old system was one of the highest in the country. Although the tax rate was 11.5%, the amount paid by operators averaged closer to 11.1%. The table below compares tax rates of operators in 2013.
The state listed above have some of the country’s best producing basins. There is a large variance in oil production is taxed. In many situations, it is a series of differing taxes that produce the rate. It is also difficult to know if the listed rate is the final as there are always additional stipulations.
The move from the trigger tax was important because of how corporations figure annual cap ex plans. This is important, as North Dakota ranks number two in states and total tax revenue coming from oil related severance taxes.
It will figure production/extraction/severance taxes just like it does drilling costs. Higher taxes can reduce how many wells an operators decides to drill in an area. In the case of EOG Resources, it may decide to spend more money developing the Permian and Eagle Ford instead of the Bakken. Lower taxes can make one play more attractive than the other, and bring additional dollars to the state. This can be seen through additional jobs in oil and gas, construction and management.
So taxes are a balancing act. In the case of the trigger tax, it is a one-time event lasting five months or more. Operators cannot plan for this break, and in turn may just postpone wells until it receives the 5% tax break. Wells already planned would just be completed at tax payer cost. A consistent tax allows for long term planning and motivates operators to move rigs to North Dakota from basins in other states like Texas. Production and severance taxes are important in how it is administered.
The last diagram shows Alaska, North Dakota and Wyoming are the most reliant on oil and gas tax revenues. Too high of a tax rate can stifle growth, and move operators to less costly states. Too low a rate, and maximum revenues aren’t realized. Some would argue, we only have so much oil and a maximum rate is ideal. This argument has merit only if production is brief. We need to focus on how long the oil run will be and if we are in it for the long haul, or a short duration. The low price environment will slow production in North Dakota, but this isn’t all bad. It will aid in spreading out production, and as oil prices recover, we will see more development in areas outside the core. We will be able to catch up with infrastructure and allow the build out of other industries.
Many think production in North Dakota will only last for 20 to 40 years. We believe this estimate is too conservative. Estimates have horizontal wells producing for approximately 40 years. That means wells today will produce at some level to roughly 2055. Depending on the area, there are anywhere from 32 to 8 wells drilled for every two sections (laterals are roughly two miles long).
The play runs from north Divide and Burke counties to its most southern border in Stark. The western border runs from the North Dakota/Montana border to central Mountrail and eastern Dunn. There are additional opportunities worth exploring in Renville and Ward counties targeting other shale. Also, development continues vertically, targeting the Red River formation in Golden Valley. When we consider all of those wells, there is additional development.
Re-fracs and waterfloods are possible, where operators can either redo wells or increase production to additional measures. We also have the Three Forks, which is between two and four additional layers to target. Even if production peaks earlier, revenues from oil will still be a major source of North Dakota income. Not to mention additional industries that will move in and stay long after the oil boom is over. This means the state needs to play very close attention to production levels, and not over tax to a point it causes operators to move elsewhere.
We already have one of the highest tax rates in the country, which may make it difficult to compete.
