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The ethane rejection / recovery election that many producers discover in their gas processing agreements is much more nuanced than just looking at the spread between CME futures for natural gas prices and ethane prices. Building a dynamic gas processing model that captures these nuances can provide producers the ability to forecast volumetric and revenue expectations, thus more accurately and optimally managing cash flow and earnings risk.

The mid-stream operator of a given gas processing plant often makes daily decisions on how to maximize the economics of a given plant within physical constraints. In most cases, the producer is provided a monthly option, exercising it prior to the beginning of the upcoming month, to reject or process ethane. Additionally, this option is bounded by contractual financial and/or operational constraints that further complicate the decision-making process. In order to maximize a producer’s expected cash flow, all contractual constraints and parameters must be accurately vetted, and the best way to ensure this is to build a gas processing model that mimics the contract specifications.

The rise in both ethane and natural gas prices this summer has created a potential competition for the BTU depending on where it is most needed in the value chain. Increased natural gas demand due to gas fired generation and LNG exports is competing with ethane as a feedstock for Gulf Coast ethylene crackers and ethane exports. A producer’s ethane election decision helps to determine which stream, ethane or methane, gets the marginal BTU on any given month – keeping in mind that midstream gas processors retain intra-month optionality when a producer decides to reject, or not recover, ethane.

Currently the Permian gas processors are the marginal unit that is making the decision on supplying ethane to the Gulf Coast. Processors at most locations that are further from the Gulf Coast than the Permian, think Rockies and Bakken, generally have operated in ethane rejection mode. As an example, the additional transport cost from the Rockies to the Permian provides some indication as to additional Ethane price increases that could be needed to balance the market should ethane supply/demand balances tighten. Current transportation economics suggests that if the Rockies were needed to become the marginal supplier of ethane to the Gulf Coast, Ethane prices could increase by approximately $0.05-0.07 / gallon while natural gas price remained static – this would currently infer ethane prices near $0.40 / gallon.

EIA reports monthly inventories for ethane but on a 2-month lagged basis, meaning the most recent data shows storage levels as of April 30, 2021 – though May storage levels will be release by the EIA later this afternoon as July comes to an end. Recall that winter storm Uri impacted the entire US Gulf Coast region shutting down power generation, residential, commercial and industrial load (demand). It has taken a while for the industrial sector to recover from Uri’s impact which means that petrochemical facilities were likely running at levels much lower than historical averages for months after the storm. This lower demand means less demand for ethane as a feedstock and thus more ethane supply headed to storage. Now that industrial demand has moved back toward more normal levels, supply/demand balances have likely started to tighten.
There are various ways to determine whether supply/demand balances are tightening but one we are particularly fond of is looking at Days-of-Coverage (DoC). This metric uses production, storage levels, estimated petrochemical feedstock demand and estimated exports to determine the DoC trend. When these variables are blended together in the calculation mix, the result indicates a tightening supply/demand balance, especially heading into 4Q2021. It’s worth noting here that the Chemical Activity Barometer, which has proven to be a strong leading indicator of industrial production, remains on a positive trajectory, albeit having slowed recently.

With a tight market for both ethane and natural gas occurring at the same time, there is the sense that a BTU competition could ensue. Imagine the scenario where Rockies producers went into ethane full recovery mode to meet Gulf Coast demand needs. This in turn would create a lower BTU residue gas which means less natural gas supply at a time when natural gas fundamentals are tight and likely to get tighter as winter approaches. In such a situation, it is likely that natural gas prices will rally further to incentivize more BTUs back into the methane stream, but this would only further tighten the market for ethane. This circular BTU competition would have to come to an end at the expense of some demand factor. Most likely this would occur in decreased exports from the Gulf Coast in either or both ethane and natural gas. But that is a Friday Focus for another Friday.

Suffice it to say, given the potential for significant dynamic market changes, the importance of proper gas processing modeling and ethane election decisions are key to ensuring optimal economic decisions are occurring expeditiously and accurately. Each processing contract has certain financial and physical limitations that can be modeled and optimized, and Mobius’ expertise ensures that our clients receive this level of detail from our analytics and advisory services.

Author Profile
Chuck Carlton
Chuck Carlton
Director, Commodity Risk

Chuck has over 20 years of experience in energy trading and analytics positions covering Natural Gas, NGLs, LNG, and Crude Oil. Chuck’s experience has included 7 years at Williams in both risk control and natural gas derivatives trading, 7 years at Citibank as a trading manager on the natural gas desk within their energy trading business, 5 years as a portfolio manager and strategist in both Natural Gas and NGL hedge funds, and 2 years as a financial analyst at Golar LNG. Chuck holds both an MBA and a BSBA in finance from the University of Tulsa.