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Rising Tides: How Does Increased Hedging Affect Crude Cash Flow?

A rising tide lifts all boats. This is true in the case of US public E&Ps, where rising WTI prices have contributed to the SPDR Oil and Gas E&P ETF outperforming the overall S&P index by six percentage points so far in 2018. However, most E&Ps have hedged a significant portion of their near term production following the crude price collapse in 2014, which typically caps the upside available to E&Ps in order to protect on the downside against potential price corrections. For this reason, we’ll look at how the hedging portfolios for a sample of public E&Ps could impact cash flow. While hedging might not impact overall US production trajectory much in the near-term  (it’s infrastructure bottlenecks currently holding that back), it could limit the upside to cash flow E&Ps can use for debt buybacks, share repurchases, and dividends.

The table below shows each operators’ average gains and losses per barrel for various WTI price points based on 2019 hedging profiles and consensus oil production. It’s important to note here that this analysis does not consider the basins where each E&P operates, but only looks at the effective WTI price that each would receive based on hedging to US benchmarks. Some producers like Apache, Continental, and EOG remain unhedged and would be fully subject to price volatility based on their disclosed hedging profiles. Other operators like Gulfport, Concho, and PDC Energy have hedged more than 40% of their 2019 production and are willing to give up pricing upside in order to protect against drastic price corrections. For example, at a WTI price of $80/bbl, Concho’s realized WTI price would be an average $12/bbl lower based on its 2019 hedging profile. However if WTI prices were to drop to $40/bbl, Concho would receive an $8 premium on each barrel.

However, there is much more pricing risk in crude markets than just WTI at Cushing. Operators and marketers need to get crude production from the wellhead to demand centers. We’ve previously talked about physical infrastructure constraints throughout the US and those have contributed to a widening of differentials to WTI, most notably in the Permian. In order to protect against widening differentials, numerous Permian operators have entered into basis swap contracts for 2019 volumes. The chart below shows the volumes and differentials contracted that various Permian operators have disclosed for 2019. Concho, for example, has almost 100 Mb/d of basis swaps contracted for 2019 at an average discount to WTI at Cushing of $2.48/bbl. This compares to a current Midland-Cushing differential of $7.75/bbl. Midland-Cushing differentials have reached as wide as $17.90/bbl in late August.

There are numerous other methods that E&Ps can use to manage physical constraints, including having firm transport out of the basin on long haul pipelines or contracts to sell crude within the basin to marketers. For example, Anadarko has stated that 100% of its 2019 operated production is expected to be covered by firm transport and Cimarex has a long-standing agreement with Plains All American to market its crude production. For this reason, while hedging is a large part of risk management, it is not the only piece. In our most recent E&P Positioning Report, we took an in depth look at transportation agreements for operators in the Permian. Additionally, in our Oil Market Outlook, we include price forecasts for major crude price hubs across the US. Follow the links to request a sample copy of these reports today.

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Matt Hagerty is the Senior Manager of Energy Markets for BTU Analytics, a FactSet Company. Matt leads the oil & gas analysis team, which delivers customized energy-market analysis from the wellhead to the burner tip, while also leading bespoke consulting engagements. Matt’s expertise spans upstream, midstream, breakeven economics, and commodity pricing dynamics for oil and gas markets. Matt holds a B.S. in Finance from Tulane University.

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