Find out what E&P companies need to know as they navigate the impact of a negative and/or depressed oil and gas commodity pricing environment.
On Monday, April 20, 2020, U.S. crude oil prices traded below zero for the first time ever, meaning producers or traders were essentially paying buyers to take crude oil off their hands. WTI opened for trading on Monday, April 20, 2020, at $18/bbl. By the end of the trading day, it had dropped to as low as minus $40/bbl.
The price crash came as the U.S. benchmark oil contract, West Texas Intermediate (WTI), headed towards its expiry date for May physical delivery, the month when lack of demand from lockdowns and travel restrictions was expected to peak. Analysts believed that a lack of available physical storage capacity at the WTI contract’s Cushing, Oklahoma, delivery point set off panic among traders holding derivative contracts. Oil futures require that holders of a derivative contract take delivery of a physical barrel when that contract expires. However, no one wanted to get crude oil delivered to them in May when physical storage capacity of the commodity was expected to be unavailable.
Although production has been curtailed, we may see negative oil again. These price disruptions will impact not only traders, but E&P, midstream, and first purchaser companies as well. To that end, we anticipate this prolonged uncertainty will likely trigger several accounting, regulatory, financial reporting, and lease-related issues.
Below are six key areas that companies should consider as they navigate the impact of negative and/or depressed oil and gas commodity pricing.
1. Revenue and Regulatory
Revenue accounting and accruals:
Negative prices would trigger considerations around how to account for revenues and revenue accruals. The price typically used for recording monthly revenue and accruals is based on:
- A monthly average
- The month-end spot price, or
- An index price, depending on what the sales contract stipulates. One-day negative price would only have a 1/30th impact on the monthly price, which is not expected to be material.
There could be a situation where even if the gross commodity price is not negative, the differentials could be equal to or higher than the low commodity price, resulting in a net zero or negative price. Another consideration for revenue accruals would be the volumes. It is typical to use an average of the last three month’s volumes to arrive at the volumes to be accrued, but with an expected increase in shut-ins (discussed later), that may no longer be a reliable measure. Companies will need to consider the shut-ins when arriving at quantities to be accrued.
A negative commodity price, either due to a negative gross price or a negative net price (with the differentials being higher than the gross price), does not necessarily mean the royalty owners would be burdened by the operator for the impact thereof. Royalty owners may be burdened, depending on what the lease stipulates. The working interest owners, however, may be burdened, depending on the provisions of the Joint Operating Agreement (JOA).
Companies will have to evaluate their leases and JOAs to better understand their legal obligations related to this matter.
Shut-ins also will cause companies to pay the minimum volume commitments (or MVCs) on their midstream contracts, which they could burden the working interest owners with, depending on the JOA. On the regulatory reporting front, companies will be required to continue to submit monthly/annual production and/or other regulatory reporting (GLO, ONRR, state, federal), severance taxes, etc., even if there is no production, unless regulatory authorities announce any relaxation.
2. Potential Shut-In
If current price trends continue, we will see producers starting to shut-in wells. Regulatory bodies are issuing orders that allow operators to halt production without breaking contracts. In part, these efforts will allow operators to hold leases when production is halted due to it being considered an “economic waste.”
The New Mexico State Land Commissioner and the Oklahoma Corporation Commission recently announced relaxed guidelines regarding shutting in wells, and other regulatory agencies such as the Texas Railroad Commission and the North Dakota Industrial Commission are expected to issue guidance soon. This will trigger considerations around a variety of land and legal matters including, but not limited to, lease and contract review, owner and royalty communications, and shut-in payment issuance.
We may also see acreage write-offs with companies no longer finding it feasible to hold the leases and the underlying acreage as they expire, or decide it is no longer economical to drill on a certain acreage. Conversely, some companies may see this as a potential investment opportunity because they would be able to acquire some leases at a much lower price in this environment.
Shutting in a well may require capital spend at the outset as well as restart costs when production is restored. This results in fixed operational expenditure (OPEX) burden, which may not necessarily have been planned.
3. Derivatives and Hedging
Lower commodity prices will have a ripple effect in company financial statements and risk management strategies. The current pricing will lead to large upward swings in valuation, leading to companies reflecting corresponding significant, unrealized gains in their financial statements.
Financial commodity derivatives are intended to be an effective hedge of forecasted physical production sales. However, the current market is facing locational supply and demand imbalances. This has led to significant basis volatility causing once highly-effective risk management strategies to be less effective.
While financial commodity derivatives are intended to protect producers’ cash flows, there may be other factors that lead producers to shut-in wells (e.g., storage constraints, significant basis discounts, etc.). In the event of well shut-ins, companies should evaluate their hedge coverage to ensure that they do not become over hedged.
Companies with three-way collars find themselves lacking adequate cash flow protection as current commodity prices have fallen well below many companies’ sold put strike prices.
Lenders often require companies to hedge a portion of forecasted production. In this environment, as companies look to mitigate future risk, they will need to ensure that restrictive lending covenants are not broken, or work with their lending institutions to ease these covenants.
4. Asset Retirement and Environmental Obligations
As operators look to shut-in wells, they should research and review relevant state laws, rules, and regulations regarding shut-in of wells. Each state is different, so it is important to research the implications. In today’s environment, we do not want to create an issue where we are required to incur expense to plug a well when operationally it is not necessary. Companies will look for statutory relief from their respective state regulatory agencies.
5. Reserve-Based Lending (RBL)
Most companies with RBLs in place are currently or soon will be working with financial institutions as the RBL is being reset based, in part, on revised reserve studies. This is going to cause further disruption as many companies are either at or close to their current debt capacity.
6. Impairment Considerations
Accounting Standards Codification Topic 350, Intangibles: Goodwill and Other (ASC 350), requires goodwill and other indefinite-lived intangible assets to be tested for impairment at least annually or when a triggering event occurs. Accounting Standards Codification Topic 360, Property, Plant and Equipment (ASC 360), requires long-lived assets to be tested for impairment when a triggering event occurs.
The market forces that have impacted the worldwide economy during Q1 of 2020 will qualify as a triggering event for both goodwill and/or long-lived asset impairment testing for some companies. As such, the longer COVID-19 disrupts businesses, the more companies will experience triggering events. As a result, more impairment charges will be taken on the financial statements of these companies.
While most segments of the economy have been hit hard by the impact of COVID-19, the energy industry has been hit even harder in recent weeks, which would result in energy-specific triggering event considerations. Full-cost companies can expect ceiling test impairments starting in Q1 and potentially even through Q4 2020 due to lower pre-tax PV10. Successful efforts companies will be impacted by the forward curve immediately. Large impairments are likely to occur in Q1 and Q2 2020.