The drama surrounding the proposed changes to the US tax system has finally run its course. The House and Senate reconciled their versions of the bills, and President Trump signed it into law. The net impact of the bill is obviously still up for academic debate, but most believe that this will certainly be a net positive – at least to the corporate bottom line, if not overall economic growth.
From an oil and gas upstream perspective, one has to wonder about the impact this new world order will have on supply and commodity prices. Given the increasing importance of US unconventional shale, understanding the after-tax economics of US operators has not been as important to understand since successes in the deepwater Gulf of Mexico started to really pick up steam in the early 1990s (interestingly, just after the last major US tax overhaul).
As much of the world has come to appreciate, the US has practically altered the entire pricing structure for crude oil. No longer is the price of oil almost completely dependent on OPEC’s swing decisions around supply quotas. The introduction of thousands of investors into short-cycle, fast ramp-up drilling means pressure on prices is increasingly a function of what a true commodity market is arguably supposed to be: lowest cost and most efficient providers win.
Few things in life are absolute, and OPEC clearly still heavily impacts the supply/demand pricing calculus. Price volatility would certainly feel the effects of member countries suddenly deciding to reverse their efforts at maintaining lower quotas. Regardless, the results of any decisions are far less certain than they were only a decade ago. Suddenly the concept of a “cue-to-drill” becomes much more important to market participants. At what price do new groups of US drillers decide to step into the market, even if their efforts only serve to defeat the impact of reduced production from other parts of the world?
As illustrated above, under the now “previous” US tax structure, Rystad Energy believes that shale and tight oil exploitation will be growing at a notably faster pace than will that of the rest of the world. Brazil will also be successfully competing for incremental investment. There is already considerable evidence for this assertion in the successes about which the country can boast through its recent bid rounds. However, the vast majority of those developments will be in longer lead time projects in the ultra-deep pre-salt “polygon”. From a purely academic perspective, facilitating US shale growth by allowing operators to keep more of their cash should strengthen the probabilities around the shale market continuing its impressive growth pattern.
Why do we care?
Relatively unique to US Shale analytics is the concept that most industry analysts benchmark wells and drilling campaigns using pre-tax economics. Understanding how every operator realistically compares on an after-tax basis is practically impossible, rendering an after-tax analysis academic at best and misleading at worst. The byzantine US tax code is hard enough to decipher on a marginal basis (e.g. MACRS asset classes, AMT, Section 179 for small businesses, etc.). Throw in the impacts related to unique tax structuring that companies frequently employ, and most would forgive an analyst for foregoing the mind-numbing exercise of calculating “incremental economics” for each operator’s consolidated operations.
Furthermore, when thinking about a cue-to-drill, most do so within the context of a breakeven price (“BEP”). All else equal, changing the tax rate for a currently tax-paying company should not materially alter that company’s BEP. All associated cost are tax deductible, even though some are deducted over time. For those who are not in a loss position and are not, therefore, paying taxes, there would be some further adjustments for net operating loss (“NOL”) carryforwards. But, again, while there would likely be some tweaks, there certainly wouldn’t be enough to move markets.
Regardless, the inconvenient truth of cash flow analysis is that investors, in general, do have to pay taxes, at least eventually. The reasons that many US operators do not currently do so are manifold and beyond the scope of this article, but most analysts would still second the idea that after-tax returns are the ultimate final arbiter of overall performance for any individual investor[1]. It is for this reason that Rystad Energy analyzed the final version of the “Tax Cuts and Jobs Act” (“TCJA”).
What is changing?
There are many changes that might be important for some companies but not others. For example, there are changes related to the Alternative Minimum Tax (“AMT”), as well as “deemed repatriation” provisions. Obviously, these are important for people to consider in their global tax planning. But for our analysis, we focused on the most material changes affecting the broadest number of investors who are focused on US shale. Therefore, the key categories changing that we reviewed are (1) marginal tax rates, (2) timing of capital deductions, (3) interest expense, and (4) the deductible amount of historical losses carried forward.
Marginal tax rates
A PhD in rocket science is not required to understand that lowering the marginal rate will, all else equal, improve after-tax returns to investors. The TCJA includes a drop in the top marginal corporate tax rate from 35% to 21%. There is also a proposed change that reflects the fact that many of the corporate investments take place within a taxing structure that is able to “pass through” the taxable income to investors, so the owners can avoid being taxed twice. This nuance is a bit more complicated, but the end result is meant to be the same – the top marginal rate is to be reduced.
Depreciation
Some might believe in the idea that the congressional efforts to reduce the tax burden will “pay for itself” through increased economic growth. At the same time, there are others who are a bit more circumspect about supply side economics and require offsets that are more concrete. Such proposed offsets have often come in the form of reduced deductions. Proponents for the tax reform might argue that limiting deductions actually fulfils one of the other goals of the overhaul, which is to simplify the entire process. Although congress is a long way from offering up a method for filling out tax returns on a single “index card-size” form, Republicans are generally stepping up to reducing the number of deductions and exemptions that individuals and companies take. Well, that is to say that they are open to the idea except in one key area – depreciation.
Under current law, drillers are able to expense operating costs and, importantly, intangible drilling costs (“IDC”). IDC represents the costs incurred that are not related to “leaving steel in the ground”, and they can typically comprise anywhere from 50% to 70% of a well’s total cost. Most of the remaining costs are subject to an accelerated depreciation system in which the expenses are depreciated over five to seven years.
The new bills take things a step further. For the next five years, companies will be able to expense 100% of capital costs. This benefit linearly phases out over a subsequent five years. The value of any tax shield is reduced when using a lower tax rate, but accelerating the recognition will help to offset the reduction in value. This benefit won’t help companies in loss positions as much since the increased deduction doesn’t do much for them. Those companies are not currently paying taxes anyway, so other than being able to carry forward the losses, not much changes for those operators. For a company that can fully utilize the deduction in the year taken, the value would clearly be higher.
Interest expense
The TCJA includes a very important reduction in how much interest companies can deduct. The previous law set no limit to this deduction, but now companies can only deduct up to 30% of their operating income, calculated as Earnings Before Interest, Taxes, Depreciation and Amortization (“EBITDA”). Unused expense can be carried forward indefinitely. This change could negatively affect companies that are heavily leveraged and are perhaps just ramping up operations. Those companies would have been in a position of offsetting much of the expected gains in income through this interest deductibility. Now, this benefit has to be spread out over time. Again, if the company is already in a position of not expecting to be paying taxes within the next five years, or their EBITDA is sufficiently large to cover the spread, this change will not have a material impact.
NOLs (Net Operating Losses)
Sticking with the example of an investor who cannot utilize existing deductions but must carry forward the NOLs into future years allows us to examine another important change for US drillers. Financial modelers will applaud one simplifying change: the elimination of the NOL “carry back”. This provision in the law currently allows filers to go back and request a refund from either of the prior two years in which they might have actually paid taxes by applying current year losses to those years’ results. One offset to this provision is the proposed elimination of the 20-year limit on loss carryforwards. Neither of these two concepts would materially impact the majority of filers. The provision that will arguably impact more companies is the one in which the amount of the NOL that can be claimed in a given year is 80% of taxable income.
Calculating the impact
For our analysis, we studied our current forecasts for a sampling of 50 US operators and calculated the average change in projected tax payments over the next five years from the implementation of the TCJA. While we did look at a couple of companies with an extremely low level of expected production (e.g. Halcon Resources), the vast majority of the operators in our sample are expected to produce at least 30,000 boe/d, and at least a dozen are expected to produce over 100,000 boe/d.
We then estimated the future capital expenditures and interest expense these companies expect to report over the next five years and calculated the impact of the new law on their forecasted payments. Many companies will have different reporting structures and other operations that support their existing debt levels. This reality renders an exact calculation impractical. However, the approach does, on average, produce a reasonable view regarding how much additional cash an “average operator” could expect to keep over the next five years.
As illustrated above, and unsurprisingly, the larger companies show up as benefitting the most by capturing the immediate reduction in future cash tax payments[2]. However, the relationship is certainly not linear. For example, EOG has roughly 60% of the (proved+unproved) reserves of Chesapeake, but their anticipated development plans indicate that they should also expect to post twice as much EBITDA. This ramp-up means that we forecast that EOG will outspend EQT by a factor of almost 2 to 1.
The leverage ratios for both EOG and Chesapeake are relatively low. EOG is carrying about $6.5 of debt for every BOE of reserves, and CHK is holding around $6 per BOE. The median operator in the sample is carrying around $12 per BOE. Therefore, the main reason that EOG will benefit more than its larger competitor will be the fact that they will be able to expense considerably more capital during their ramp-up phase. Their already sizable EBITDA means that, assuming they maintain a consistent debt/reserve ratio, they will also be able to expense the full amount of interest that they are paying, and they should be able to more quickly capture any NOLs.
We find that operating cash flows for all shale drillers could increase by more than $5 billion per year thanks to the new TCJA. On average, assuming the sample is a reasonable representation of the overall industry, we expect that the TCJA will create upwards of $250 million to $300 million per year in tax benefits to US operators.
Given the weighting of the larger companies’ results, we also looked at the median (P50) savings, which were closer to around $100 million per year. Clearly, the larger companies will benefit considerably more than the smaller ones. Specifically, using these calculations, companies with entitlement production greater than 100,000 boe/d should generate around $150 million per year, but the smaller companies will generate only around $20 million per year. In fact, the very small companies (<30,000 boe/d) will most likely not benefit at all, with some actually posting decreased cash flow. If the company was expected to be a current tax payer on a consolidated basis, lowering the marginal rate results in less value for the future income offsets.
The net result
Clearly, the true impact will depend on the specific situation of each operator, but there is plenty of reason to believe that cash flow should improve for most operators. The question that many are therefore asking is, “So what? What will they do with the extra cash?” Will they hire more people because they will be moving into new areas? Again, BEP should not be changing that much. Therefore, if their cost structures are already above their BEPs, lowering taxes on profits that are not there will not entice them to expand beyond where they already operate.
That being noted, the notional capacity for expansion should increase by the ability to spend that extra cash on additional drilling. With an average well costing anywhere from $4 million to $8 million per well, this incremental cash should, at least theoretically, support anywhere from 0 to 5 additional wells for the smaller companies and 20 to 40 additional wells for the larger operators.
Using information from Rystad’s NASWellCube, we analyzed the average production for an average well drilled over the last three years. Using that information, one could assume that a new well would produce an average of 300 bbl/d oil over the first year. Using a generalized assumption of around 250 small companies and 25 larger companies that would produce a meaningful level of hydrocarbons, our calculations indicate that the incremental available cash could result in an additional 1000 wells being drilled each year, approximately half from each size group.
We further assume wells will be drilled in areas with yet no infrastructure bottlenecks and that the service industry has capacity to grow at this moderate pace in 2018 with manageable service cost increases. This level of additional drilling would create approximately 300,000 bbl/d of additional production after 12 months and more than 500,000 bbl/d of additional production after three years. For 2018 the impact will be about 200,000 bbl/d in additional December 2018 production. The soonest that this impact could become visible would be mid-2018 due to decision delays, time to spud and times to complete and turn in-line new wells.
