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Turbulent Markets Force Forecast Revisions

The recent decision by Saudi Arabia and Russia to suspend OPEC+ production cuts, as well as the increasing impact of the COVID-19 pandemic, has led BTU Analytics to significantly revise the US production forecast for both oil and gas. With oil prices cratering following the announcement by Saudi Arabia to return curtailed production, producers have already begun to issue new guidance for drilling activity in 2020. While plenty of uncertainty remains surrounding the ultimate impact of COVID-19 and how much OPEC+ production will return, the analysis below will highlight the most important factors underlying the current BTU Analytics forecast and risks.

In last month’s E&P Investment Highlights piece, BTU Analytics discussed potential impacts of COVID-19 on global liquids demand. In the February BTU Base Case, global liquids demand was projected to increase 0.65 MMb/d in 2020 factoring in a 0.5 MMb/d in demand loss compared to our January 2020 estimates. Now though, all of the demand growth originally expected for 2020 is in jeopardy with many estimates expecting demand to decline in 2020 compared to 2019. On March 9, the IEA revised its demand outlook for 2020 to a decline of 90 Mb/d compared to 2019 levels. As COVID-19 has continued to spread into a global pandemic, it is becoming increasingly likely that even this estimate maybe to high. In 2008 and 2009, Global liquids demand contracted by 1.7 MMb/d from 2007 levels before rebounding in 2010 by over 2.8 MMb/d.

Last month, in discussing the potential extension of OPEC+ production cuts, BTU Analytics noted that “Russia has yet to agree to either recommendation” despite support voiced from other OPEC+ members. Unfortunately, that proved to be prescient as Russia rejected both recommendations placing the global oil balance in jeopardy. In response, Saudi Arabia has slashed prices and is planning to bring back curtailed production leading to significant downward pressure on global oil prices. With no resolution in sight, the global market could see all 2.1 MMb/d of OPEC+ production return not including any announced increases in production from Saudi Arabia and the UAE. This does not include 1 MMb/d of Libyan production that could return in the second half of 2020. Taken together, the increased impact to demand from COVID-19 and the return of OPEC+ production could total more than 4 MMb/d, which would far outpace cuts to US shale production.

The continued impact from COVID-19 and the new supply shock from the OPEC+ announcement have combined to drive WTI pricing lower by almost 50% since the beginning of the new year. Beginning with the outbreak of COVID-19 in China in late January, WTI fell sharply to $50, but rebounded slightly after the proposal of additional OPEC+ production cuts in early February. However, after the virus became more widespread, pricing continued to drop culminating with the Saudi Arabia announcement to return all production sending WTI plunging below $30.

At current WTI pricing of approximately $30/bbl, few, if any, operators can afford to continue drilling operations. The chart below depicts EUR-weighted company breakevens by basin for the top operators in major US oil plays. Even operators with the best economics are under water at $30 WTI once corporate costs are factored into company breakeven levels. Given the current level of breakevens in US oil plays, WTI likely needs to rise to $45/bbl to ensure operator profitability. While projected US oil production was approximately 46% hedged according to most recent earnings releases (see the Investment Highlights piece on pg. 5 for more information), it doesn’t appear that it has mitigated producers’ responses to falling prices.

Already we have seen announcements to curtail drilling and completion activity as soon as possible. Early announcers included Diamondback Energy (NASDQ: FANG) and Parsley Energy (NYSE: PE). FANG announced they had dropped from nine frac crews to six over the weekend with plans to drop three rigs in the second quarter of 2020. Parsley announced reducing rigs and completion crews by 30% with plans to further reduce activity. Other companies to publicly announce cuts to activity include Occidental Petroleum (NYSE: OXY), Matador Resources (NYSE: MTDR), Marathon Oil (NYSE: MRO), and PDC Energy (NYSE: PDC) with more companies sure to follow. See pg. 5 for a detailed updated on CAPEX plans for 2020.

While completion activity can readily be brought to a standstill, drilling is often slower to react due to less flexible contracts for drilling rigs. In the near term, this lag between completions and drilling will serve to build DUCs, similar to what occurred in 2015-2016. In the long term, these DUCs will likely be worked off once activity begins to rebound as completing DUCs represents a more efficient use of capital. This dynamic is illustrated in the new BTU forecast with wells drilled declining at a slower rate than wells to sale in the first half of 2020. However, beginning in the summer of 2021, that trend reverses with completions eating into the DUC backlog before drilling activity fully recovers to the same level.

Given the significant levels of cuts already announced my major producers, BTU Analytics has revised down forecasts for both wells drilled and wells to sale, especially in the near term. Relative to the previous forecast, wells to sale was revised down approximately 30% in 2Q 2020 and 15% for the second half of 2020 through 2021. Wells drilled was revised down approximately 15% beginning in June 2020 through the end of 2021. The revisions now show a reduction in activity year over year of -29% for wells to sale and -25% for wells drilled with the largest reductions occurring in Oklahoma (-48% YoY) and the Rockies (-30% YoY).

With both COVID-19 and OPEC+ production predominantly impacting the global crude market, US crude production will be most heavily affected by cuts to activity. Compared to the previous forecast, US lower 48 crude production has been revised down by an average of 623 Mb/d in the second half of 2020 and 827 Mb/d in 2021 and 2022. Total lower 48 oil production is now expected to decline by 316 Mb/d exit 2019 to exit 2020 compared to 311 Mb/d of growth in the previous forecast.

While the BTU Analytics’ forecast currently incorporates a 30% cut in completion activity in the near term, uncertainty in the market leaves potential for even greater downside to drilling activity. If prices remain depressed, operators could extend cuts further into 2020 rather than experiencing a slight rebound in the second half of the year. Under this scenario, lower 48 production would average 1.1 MMb/d lower than the previous forecast in the second half of 2020 and represent a 1 MMb/d decline exit 2019 to exit 2020.

While the brunt of the impact of returning OPEC production will be felt in US oil production, the US gas market will also feel the effects of decreased drilling activity. Specifically, declines in drilling activity in oil-focused plays will result in a significant decrease in associated gas production. The 20% projected decline in completions activity results in an average downward revision of 1.8 Bcf/d in the second half of 2020 through the end of 2021. In combination with previously modeled declines in dry gas production in Appalachia and Northern Louisiana, dry gas production is now projected to decline by 4.7 Bcf/d exit 2019 to exit 2020. In the low case scenario, a 40% decline in activity would decrease production by 2.5 Bcf/d in the second half of 2020 with the exit 2019 to exit 2020 decrease totaling 6.1 Bcf/d.

However, while gas production is expected to decrease in the near term, BTU Analytics models a quicker rebound for dry gas production mainly driven by increased activity in the Haynesville and Appalachia. Relative to the previous forecast, BTU Analytics has added approximately 0.15 Bcf/d of production to the Haynesville in 2020 and 2021 before increasing production in 2022 and beyond to meet projected LNG growth along the Gulf Coast. In Appalachia, BTU Analytics has further deepened production cuts in 2020 by an average of 0.6 Bcf/d due to the current low gas price environment. However, activity is projected to return in 2021 leading to an increase of 0.8 Bcf/d on average by 2022 relative to the previous forecast. If oil-driven activity falls off even harder than expected, Appalachian and Haynesville production could see an even quicker resurgence to backfill for lower associated gas production.

Given the uncertainty surrounding both supply and demand in the global market, there exists significant risk to the current BTU forecast. On the low side, a full return of OPEC+ production and continued demand destruction from COVID-19 could lead to sustained low crude pricing through the summer of 2020 leading to even steeper declines in activity than presented in the BTU forecast. However, should OPEC+ reach an agreement to reinstate previous production cuts, crude pricing could see an immediate rebound supporting an uptick in activity in the back half of the year.

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Joe Warner is a Senior Energy Analyst at BTU Analytics, a FactSet Company. He focuses primarily on power market data and analysis including capacity, generation, and emissions within ISOs and utility areas across the US. Prior to joining BTU Analytics, he worked on income tax compliance and consulting for private equity-backed upstream oil and gas investment partnerships. Joe is a licensed CPA (inactive) in Colorado and holds a B.S. in Accounting and Financial Management with a minor in Economics from the University of Colorado Denver.

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