Analysing federal policy changes in US oil and gas with GlobalData10 April 2018
GlobalData analysis lifts the lid on the state of the US oil sector at a time of great upheaval for the domestic market and its counterparts around the world.
The combination of state and federal control over oil and gas operations leaves the industry exposed to the prevailing attitudes towards it. At the federal level, partisanship surrounding environmental policy adds exposure to risk throughout political cycles, although currently the Republican Party is largely in favour of supporting oil and gas activity.
At the state level, similar partisanship also exists, but the reliance on revenue from the oil and gas industry in certain states can increase the risk that state governments will try to extract additional money through taxes.
To that end, some states are looking to introduce – or increase existing – production taxes on hydrocarbons. In response to structurally lower oil and gas prices relative to 2014, state-level initiatives to increase the tax base through increased production-based taxes represent a risk for the upstream sector.
In February 2017, Ohio Governor John Kasich introduced provisions in his budget proposal to introduce a 6.5% severance tax on oil and a 4.5% rate on gas, representing a significant increase in the existing unit-based tax rates of $0.20 a barrel (bbl) of oil and $0.03/mcf of gas.
The measure was not included in the final version of the state budget, but Kasich’s previous attempt to increase the severance tax indicates the governor believes this would be a viable revenue-generating option for the state. In neighbouring Pennsylvania, a 6.5% severance tax on gas was also proposed in the governor’s budget in February 2017. Pennsylvania is the only major gas-producing state that does not levy severance taxes, and where numerous past attempts to introduce a charge have been thwarted.
One proposal, helped by the pressure of a state budget deficit, was passed by the Senate in July, but failed to progress in the House, where a proposal is now being introduced which would levy a 3.2% severance tax on top of the existing drilling fee. Although the measures in Ohio are unlikely to progress in the near term and significant uncertainty remains on the prospects for a severance tax in Pennsylvania, they demonstrate some willingness of states to respond to state-level revenue shortfalls or perceived windfalls in the upstream sector to introduce substantial new taxes.
The application of production-based taxes could disproportionately hurt economically marginal developments and could inadvertently perpetuate production declines in states employing them.
Pennsylvania and Ohio have seen production declines from 2015 following large increases in the previous decade, and the application of additional production taxes could encourage some producers to increase profits by rationalising costs, rather than expanding production.
Operators in states with meaningful levels of oil and gas production, which also have challenged public finances, are vulnerable to such tax changes in the event of deterioration in commodity prices or in economic conditions.
In response to similar revenue pressures, there is a risk that some states may remove favourable tax incentives; after having changed the severance tax structure in 2015, implementing a 2% tax on oil and gas for a field’s first three years after which the rate increased to the standard level of 7%, some stakeholders have sought to eliminate Oklahoma’s temporary reduced 2% rate.
As the state is currently in an ongoing budget crisis, for which tax cuts for drillers have been cited as being partly responsible, the issue was reviewed in the first half of 2017 and resulted in a watering down of the initial plan. Instead, House Bills have targeted older incentives to increase the horizontal well incentive production tax rate from 1% to 4%.
Policies that are targeted to be implemented under the Trump administration will decrease the regulatory burden on operators and will open up previously prohibited acreage for mineral leasing, although political disunity in the Republican Party threatens to impede or slow this agenda. Of these potential changes, moves to deregulate the upstream sector are more likely to occur and are more likely to be implemented in the near term, as a result of President Trump’s executive order on promoting energy on 28 March 2017.
Independence and Economic Growth, Environmental Protection Agency (EPA) and Bureau of Land Management (BLM) rules on limiting methane and other greenhouse gases (GHGs) were put under review and could be removed.
Following the executive order, in April 2017, the EPA delayed the June 2017 compliance date for its regulations limiting methane and other GHG emissions from new and recompleted operations, in order to review the regulations. Because the EPA rules apply to public and private lands, any repeal of the requirements following the agency’s review could decrease regulatory compliance costs for independent producers.
Although a vote to repeal the BLM methane regulation passed through the House in February 2017, it stalled in the Senate in March before being defeated in May.
As a response, Interior Secretary Ryan Zinke attempted to delay the rules implementation until 2018, though this has been shut down in the courts. The failure of the repeal measures exposed the lack of political consensus within the Republican Party for a broad-based agenda of deregulation and highlight the limits of the White House to act independently.
Any repeal of the BLM regulations, which create rules for flaring, pre-drilling planning, and leak detection, would allow upstream acreage on federal lands to maintain competitiveness with the regulatory burden for leases on non-federal land; the BLM regulations only apply to federal land, and the requirement of additional emission control systems on marginal wells could render a large number of wells on these lands uneconomic.
Wider federal policy changes could also strongly impact operators in the US onshore sector, but their outcome is uncertain. The Trump administration’s tax reform proposals would reduce the top federal marginal tax rate from 35 to 20% and allow investments to be immediately deducted from taxable income for the next five years.
These proposals could significantly reduce operators’ tax burdens and improve profitability. However, a current lack of detail and doubt regarding the timeline of implementation of tax reform leave the outcome uncertain.
Corridors of uncertainty
Treasury Secretary Steven Mnuchin noted that the administration’s prior goal of having tax reform legislation completed by August 2017 was too aggressive a timeline, but that legislation would be finalised by the end of the calendar year. However, the administration’s failure in its attempts to pass a healthcare bill show that legislative progress is far from certain, despite the Republicans controlling both houses of congress.
A failure to pass tax reform legislation before the 2018 mid-term elections, if the elections were to result in an increase in Democratic control of Congress, would significantly threaten the passage of tax reform in its proposed form. Besides tax reform, the upstream sector in the onshore US may be affected by future policy measures relating to federal land. President Trump’s energy policy statement mentions potential drilling opportunities on federal lands that may be pursued, and Trump’s pick for interior secretary, Ryan Zinke, has speculated that the Trump administration could amend Obama-era orders declaring millions of acres of federal land as monuments. Such efforts could potentially open new unexplored acreage for bidding, but there is also potential for negative changes to the federal lands regime.
The Interior Department announced in March 2017 that it would establish a new committee to review federal royalty rates for oil and gas on federal land in order to ensure that taxpayers were receiving adequate value from the resources.
Given the focus of the committee, despite the pro-energy political platform of the Trump administration, there is a risk that minimum royalty rates for onshore developments could be increased as a result of the committee’s recommendations.
The broader push towards deregulation, given the administration’s pledge to maintain as little regulation as is necessary, could signal a positive step for the industry. However, over the longer term regulatory policies could prove more volatile; even if the Republican Party can maintain unity to move forward with key pieces of legislation focused on deregulation, there is no guarantee that Trump will win a second term.
Moreover, given the starkly divergent environmental regulatory agendas of the two major parties, continued changes in leadership could result in ongoing application and repeal of burdensome regulations over the medium to long term.
Taxes and regulations
State-level measures to increase taxes on production, or to remove production tax incentives, represent a risk to operators in states with challenged public finances, particularly in the event of declines in commodity prices or economic conditions.
Although the current government is aiming to reduce regulatory burden across all sectors, disunity within the Republican Party and political deadlock have so far severely limited the ability of the government to make significant progress in enacting legislation. The Trump administration’s tax reform proposals could reduce corporate tax burdens, particularly through reduction of the top marginal tax rate from 35 to 20%. However, the full details and potential for legislative progress remain uncertain.
Upstream oil and gas operations on in the Lower 48 states of the US are authorised through leases with landholders, whether private or governmental, operating under a royalty/tax system. Biddable bonuses may be applied, and per-acre rental payments, generally $1–10, are typically required for leases.
Royalties are governed by individual lease agreements, with rates are generally between 12.5 and 25.0%. Operators are required to pay local property taxes and state-level corporate income taxes for most states, and often are required to pay production taxes on oil and gas as well as additional administrative fees.
Levels of state take in the US Lower 48 can vary significantly depending on the levels of royalties and taxes levied by individual states.
Variations in production taxes, and state corporate income tax do affect levels of state take, as shown by the relatively low level of state take in Pennsylvania compared with West Virginia caused by the former’s lack of a production tax (the Pennsylvania drilling impact fee is not considered).
However, the primary cause of the differences in this comparison are levels of royalties on state lands. Texas’s 25% standard rate for onshore state land compares unfavourably to just 12.5% in Pennsylvania, West Virginia and Ohio, but the 12.5% royalty rate that applies to Texan state waters is much more attractive, reducing state take to 60% for oil and 82% for gas.
This importance of royalties to the overall fiscal burden is extremely significant, due to the fact that much of the country’s oil and gas production is located on privately owned land, where leases have individually negotiated royalty rates, or on federal land, for which the standard royalty rate is 12.5%.
The average tax burden in the Lower 48 states is in the mid-range for the region, and similar to that in Alaska. The primary difference between the fiscal regimes of the Lower 48 and the US’s neighbours lies in the fact that royalties and production taxes in the US are generally flat rates.
In contrast, the Albertan royalty regime in Canada and the royalty/tax regime used for licensing onshore areas in Mexico have in-built mechanisms adjusting to prevailing commodity prices and production, potentially shielding profit margins from low prices, particularly in the case of natural gas.
However, the impact of these differences between regimes will vary and may be outweighed by other comparative advantages linked to the advanced state of the upstream sector in the US, particularly for unconventional resources.
Lessees generally pay a cash bonus up front to the rights owner upon the signature of a mineral lease. The value of the bonus, denominated on a per-acre basis, may be determined by competitive bids or individual negotiations depending on the leasing process. For competitive lease sales, a minimum bid per acre is typically set by the lessor prior to sale; for federal leases this is $2/acre.
Under most oil and gas leases, an annual rental fee is payable at a rate set by the lessor prior to the lease sale. For federal leases, the rental rate is $1.50/ acre during the first five years of the lease, and $2/acre thereafter.
Typically, rental fees are not paid for leases with production, with royalty payments being the form of remuneration to lessors.
Royalties are payable to the lessor on the value of gross production, although in some cases leases may stipulate that royalties are calculated on the wellhead value.
Although private landowners may apply royalty rates of their own choosing for mineral leases, leases on state lands are generally subject to minimum or specified royalty rates. For federal lands, the standard royalty rate is 12.5%.
Property taxes are typically levied on the assessed value of real property.
Property tax systems are generally structured at the state level, where the assessment ratio, or the percentage of the true market value of the property, is determined.
Tax rates, generally 0–2% of the assessed value, are then determined at the county or local levels.
Some states may also levy ad valorem property taxes on the value oil and gas present in a given lease.
Federal corporate income tax is payable on taxable income in the US based on a tiered system whereby each tranche of a corporation’s income is taxed at the rate applicable for that specific tranche.
For the calculation of federal corporate income tax, assets are depreciated according to the current federal tax code.
Royalties, state corporate income tax, operating costs, and intangible drilling costs may be deducted as they are incurred. Exploration costs may either be capitalised or deducted in the first year of production if incurred prior to first production.
Capital assets are depreciated under MACRS under either the General Depreciation System (GDS) or the Alternative Depreciation System (ADS), with depreciation starting in the year in which it was incurred or in the year of first production, whichever is later, at rates depending on the system and asset life.
Most oil and gas exploration, and production assets are depreciated according to the seven-year GDS schedule, while drilling costs are depreciated according to the five-year GDS schedule. Tax losses may be carried forward for up to 20 years and carried back up to two years.
A depletion allowance may be available to independent oil and gas producers under certain circumstances. This is usually up to 15% of gross revenue, but may also be subject to other limitations. Natural gas sold under a fixed contract may qualify for a 22% depletion rate.