Associated gas plays lead US production higher despite steady fall in rig count

Analysis: Associated gas plays lead US production higher despite steady fall in rig count

spglobal.com  8 Jul 2020  Author  J. Robinson   Editor  Keiron Greenhalgh

Highlights

Previously curtailed wells lift output to eight-week high

Permian production rises 430 MMcf/d on the month

More supply growth forecast, despite low rig counts

Denver — Associated natural gas production from some of the largest US crude basins is on the rebound in July as previously curtailed wells are brought back online, lifting total output to its highest since early May.

So far in July, gas production from the Permian Basin, the Eagle Ford Shale, the Denver-Julesburg Basin and the Bakken Shale is up about 430 MMcf/d, 300 MMcf/d, 140 MMcf/d and 130 MMcf/d, respectively, compared with each basin's June average, data compiled by S&P Global Platts Analytics shows.

In the Permian, cash prices at the basin's benchmark Waha hub are down sharply in response to the additional supply, averaging $1.12/MMBtu so far this month, about 25 cents weaker than in June. In the Rockies, prices at the Denver-Julesburg's nearby Cheyenne Hub are down about 5 cents on the month.

In the South Texas and the Midcontinent, cash markets at upstream hubs servicing the Eagle Ford and the Bakken, respectively, are up about 4 to 5 cents in July, mostly owing to a recent tightening in regional supplies due to a stronger power burns and a drop in Appalachian production.

At the national level, recent increases from associated gas plays have lifted total production to an average of 87.3 Bcf/d over the past seven days – its highest in about eight weeks, according to Platts Analytics.

Rig counts

Rising associated gas production in major US crude plays comes as many operators appear to be hitting the brakes on recent production curtailments, even as they continue to pull back on drilling activity.

In mid-June, Continental Resources said it would restart over 50% of its previously curtailed oil production in July. Other shale players including WPX Energy, EOG Resources and Parsley Energy said previously that they too were beginning, or planning, to bring more production back online.

Moves to restore mothballed production come as US benchmark crude prices continue to edge higher, averaging over $40/b this month, according to S&P Global Platts data.

Recent market bullishness has not been enough to stem the tide on drilling curtailments, though. On July 2, total US rig deployments were estimated at another record low, totaling just 285 – down by over 65% from an annual high at 841 rigs, data published by Enverus DrillingInfo showed.

The Permian has been the hardest hit, shedding 289 rigs since early March to reach a total of just 140 as of July 2. Over the same four-month period, the Eagle Ford shed 70 rigs to reach nine currently; the Bakken has shipped 43 rigs to stand at 10, while producers in the Denver-Julesburg have pulled 25 rigs to leave just three operating currently.

Supply growth

According to Platts Analytics, rebounding production from previously curtailed wells should continue lifting US output this month, which is forecast to average over 89 Bcf/d. By August, production could top 90 Bcf/d, before edging back to the 86 Bcf/d to 88 Bcf/d range over the balance of 2020.

As US output continues to rise this summer amid weakened demand from the LNG and industrial sectors, more gas is likely to find its way into storage, potentially pushing inventories to capacity before the traditional injection season ends in early November.

On July 9, the US Energy Information Administration is expected to announce a 53 Bcf injection, lifting total stocks to 3.132 Tcf for the week that ended July 3, according to the consensus expectations of a survey of analysts by S&P Global Platts.

At current levels, five-year average builds over the balance of injection season would lift stocks above their previous historic record high of 4.05 Tcf by mid-October.

Despite significant downside risk to spot gas markets come early autumn, the Henry Hub October forward was most recently assessed at $2.03/MMBtu on July 7, up from a record low of $1.73/MMBtu on June 26, S&P Global Platts M2MS data shows.

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U.S. Supply Curtailments Could Return by 3Q if WTI Crude Prices Hold Near $40/Bbl

 By Leticia Gonzales   July 8, 2020 naturalgasintel.com

If current West Texas Intermediate (WTI) crude oil prices of around $40/bbl are sustained, all previously curtailed U.S. production would return by the end of September, according to Morgan Stanley researchers.

In a mid-year outlook issued Wednesday, the Morgan Stanley team, led by Equity Analysts & Commodities Strategist Devin McDermott, said the industry is in the first of a three-phase recovery. This first phase — reversal of curtailments — requires a WTI crude oil price of $25-30, while the second phase of production stabilization would require a WTI price of roughly $40 in order to hold 4Q2020 production levels flat. The final phase, according to Morgan Stanley, is the resumption of growth, which needs WTI prices to be around $40-50.

“With WTI now back around $40/bbl, pipeline flows suggest around 1 million b/d of curtailments have been reversed over the past few weeks,” researchers said. “If current prices hold, we believe effectively all curtailed volumes will return by the end of 3Q.”

On average, Morgan Stanley’s 2020 and 2021 WTI price outlook remains unchanged at $38 and $40, respectively, while its 2022 estimate is down to $42, versus $44 prior. Researchers see Henry Hub natural gas prices falling 10% to $1.94/MMBtu for 2020 and declining 3% to $2.65 in 2021. The team maintains their long-term assumptions of $42.50 WTI and $2.75 Henry Hub.

On Tuesday, the Energy Information Administration (EIA) updated its own price forecast, knocking down Henry Hub prices for 2020 another 11 cents from the previous outlook to $1.93. In the latest Short-Term Energy Outlook (STEO), EIA said it expects the Henry Hub price to average $3.10 in 2021, 2 cents higher than forecast in the previous STEO, as falling production levels continue to exert upward price pressures.

In a note to clients on Wednesday, Enverus said that after bottoming in May, natural gas pipeline data indicates that production has started to flatten, and in some areas, has shown gains. The pipeline sample, which represents 74% of the total gas produced in the United States, declined from 71 Bcf/d in January to 65.7 Bcf/d in May. As of June 23, production averaged 65.1 Bcf/d.

Pipeline scrapes show gas production June to date in some key plays trending higher compared to May, including in Appalachia and the Permian, Anadarko, Powder River and Williston basins.

“Despite these gains, production for the U.S. is still down in June,” Enverus analysts said. “However, it shows how U.S. operators can be resilient even during times when most of these areas are not economical.”

After plunging deep into negative territory in April, higher WTI prices have incentivized some producers to turn back on the taps. However, Enverus pointed out that this price level still leaves only a handful of areas with gas breakevens under $5/MMBtu, most predominantly in the Marcellus/Utica and Haynesville shales.

Nevertheless, the risk of ending the traditional storage season at “significantly” above-average levels is high, Enerverus said, due to expectations that demand destruction from Covid-19 mitigation efforts would initially outpace production shut-ins. Lower 48 inventories already are tracking well ahead of historical levels, sitting at 3.012 Tcf as of June 19, which is 466 Bcf above the five-year average, according to EIA.

However, by the start of the withdrawal season, and with production declines taking hold, storage inventories may decline rapidly as demand normalizes and the winter season gets under way.

“Using current forward prices as of June 24, inventories would reach a record low of -0.1 Tcf by the end of winter 2020-21,” Enverus said. The firm therefore expects a price response that would push Henry Hub to $3.90/MMBtu for winter 2020-21.

“This price response will affect forecasted production, power demand and liquefied natural gas exports in order to balance the market in summer 2021,” analysts said.

 

 

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