Capturing Shut-Ins in Real-Time
The oil markets are searching for balance as the world reflects on the impact of the COVID-19 pandemic. The market has never experienced such a demand shock and it is difficult to predict what will happen next. What we do know, is that U.S. producers have made drastic changes to overcome the excess supply in the market. Since the beginning of April, our U.S. Daily Oil Production data, shows that total U.S. production has dropped 1.5 million bpd. That’s approximately 11 percent of daily barrels-out-of-the-ground removed from the market due to price-driven shut-ins. It’s hard to swallow just how impactful this dip in production is – and there are many factors at play in the market today. In this post, we will discuss how we’ve been tracking and corroborating shut-ins, impacted regions, and our thoughts on recovery.
Regional Assessments of Production
In April, our U.S. daily oil production model began showing a meaningful downward response to market pressures. Because our data is broken out into eight different regions, we saw that this decline was driven by the Permian, which fell off by 366,000 bpd from March to April and has continued to drop through this month. Despite the Texas Railroad Commission’s decision to not intervene in the market, operators are curtailing their own production through a market-driven exodus. As of May 19, our research showed that cumulative impact of announced May shut-ins in this basin is 357,000 bpd. These announcements make up about half of the total shut-ins implied from our daily Permian model, which also includes unannounced shut-ins. Though it did not show as an intense nor rapid response, production in the Eagle Ford has fallen off by about 125,000 bpd since March. While the shut-ins started in Texas, more followed in the Bakken and Gulf of Mexico.
Bakken production data recently published by the North Dakota Industrial Commission (NDIC) shows that March production came in at 1.428 million bpd, just above our modeled 1.422 million bpd. Between March 13 and May 15, our North Dakota model showed a 410,000 bpd decline, dipping below 1 million barrels at its lowest point. The NDIC also cited on May 15 that production has dipped below 1 million bpd, and that “it is going to be a rather slow process to get production back online .” However, just last week we saw about 100,000 bpd of recovery in this region, which has risen with local hub pricing. This recovery may not last, but initial signals have shown that production is rebounding in response to the latest price rallies.
The Gulf of Mexico has been hit just as hard as some onshore fields, despite expectations of resiliency due to larger projects with higher overhead. Since March, we’ve observed production fall off by over 200,000 bpd. At first, this decline was spread evenly across fields (we model production at 12 separate offshore platforms) and corroborated by April 22 shut-in announcements from Cantium and Fieldwood Energy. On May 2, the Delta House platform shut-in and production dropped to zero. During their May 11 earnings call, Kosmos Energy revealed that the platform’s operator had decided to shut the field for the entire month of May and move up their maintenance schedule. Our model captured this shut-in ten days in advance and our subscribers will know as soon as production ramps back up again. Previously, our data has accurately predicted production recovery following hurricanes, and our model will also capture the next uptick in offshore production.
Keep in mind that shut-ins are not uniform. Certain operators, like Exxon Mobil, are shutting in their most productive wells (according to their May 1 earnings call), while others such as Parsley are shutting in least economic wells. Some are running wells until failure, and others are chartering crude tankers for extra storage space. Still, we’re now seeing sweeping declines across the regions that we model for – which drive our total estimate of crude production in the United States.
Figure 2: Regional breakdown of weekly change in crude production. Hover over bubbles to see production numbers. Source: Genscape
Figure 2 above represents our regional production coverage and total U.S. Production in real time. Our U.S. Daily Oil Production model covers eight main regions, twelve Gulf of Mexico sub-regions, and a total U.S. production estimate. The model utilizes our Oil and Natural Gas Intelligence platforms for real-time inputs, including oil pipeline flow volumes, crude-by-rail cargo counting, and natural gas nominations. Using this data, we're able to capture a daily production estimate in the following regions with high accuracy: Permian, Gulf of Mexico, Eagle Ford, Bakken, DJ Basin, Alaska, Wyoming, and California. All other U.S. production regions are captured in our total U.S. production number. This accuracy creates user confidence and helps answer the next question, when will U.S. production reach the bottom and begin recovery?
Calling the Bottom and Capturing Recovery
As a result of these declines in our daily estimates, we have lowered our short term total U.S. production forecast significantly in Q2-2020 to take into account the shut-ins and completion deferrals. We expect that production will drop nearly 1.9 million bpd, from 12.8 million bpd in March to 10.9 million bpd in June. Of this reduction, we assume nearly 1.1 million bpd come from shut-ins, while 800,000 bpd is related to completion deferrals and rig activity reductions. We could see a jump in production by the end of June as curtailments come back online, however there is risk to this depending on how quickly demand recovers and where storage levels sit. The timing and volume could be dependent on if wells need workover activity or if they actually come back at higher levels due to pressure build up and flush production.
In fact, we’ve seen some incremental growth driven by North Dakota and the Gulf, signaling that production could be recovering sooner than expected. Local hubs like Clearbrook and Midland both have traded above WTI since late April/early May, improving the margin on barrels produced in these regions. Still, since we have never seen widespread production shut-in like this in the past, many questions remain about how much volume will return and if smaller producing higher cost wells may be shut-in for good.
Keep in mind that our forecast will change according to prices and the now bottomed-out rig count, and that we provide our clients with a weekly update of our forward-looking expectations based on these inputs. Regardless of when production comes back, our users will be able to capture and quantify the recovery as it happens. Just as our data was a leading indicator of the first shut-ins, it will catch production on the way up. This will allow our clients to be able to update their balances in near real-time and respond to production movements appropriately.
Watch What Happens Next
For years, U.S. crude production has been marked by steady, seemingly unstoppable growth. The drastic imbalance of oversupply in a market suppressed by a demand-choking pandemic has driven prices to historic lows. The resulting production dive is nearly indescribable, but nothing short of unprecedented. Data describes the situation much better than words, which is why we strive to provide the most accurate and high-frequency assessment of crude production in a cloudy market. The combined analytical expertise and powerful daily modeling of Genscape’s U.S. Crude Production suite will help you capitalize on upstream uncertainty. Join us in following shut-ins and capture crude recovery. To learn more about our services or speak with an expert, click here.