Special Report:
US Shales Scorecard
Special Report:
US Shales Scorecard
US Shales in 2020
An in-depth analysis shows what went right and what didn’t in 2020 and the game changer that could push each major North American shale basin into prosperity in 2021.
Analysis by Enverus
The Haynesville, with ample takeaway capacity and being a gas-focused basin, will be called upon to help offset the natural gas deficit.
(Source: Marc Morrison/marcmorrison.com)
The Haynesville, with ample takeaway capacity and being a gas-focused basin, will be called upon to help offset the natural gas deficit.
(Source: Marc Morrison/marcmorrison.com)
An in-depth analysis shows what went right and what didn’t in 2020 and the game changer that could push each major North American shale basin into prosperity in 2021.
Analysis by Enverus
A

s the industry often does, it will one day look back on 2020 in a variety of contexts—how demand destruction and a global price war sunk oil prices to previously unseen levels, how mounting debt problems coupled with a lack of investment opportunities drove widespread consolidation, and how production shut-ins crippled operators.

The 2020 details vary depending on which of the seven major shale basins are being reviewed:

  • Activity dropped to merely a crawl in places like the Rockies and the Midcontinent;
  • The Permian behemoth took a punch but quickly got up off the mat; and
  • Gas plays like the Haynesville and Marcellus/Utica rode on the coattails of Henry Hub prices that reached $3/MMBtu by early fall 2020.

The summer of 2020 was marked by unprecedented headwinds for the shale industry—for producers and service providers alike. WTI fell into negative valuation in May as a result of a lack of storage capacity coupled with overproduction. By mid-August, the number of rigs operating in North America had fallen to 244, the fewest since Baker Hughes began tracking rig counts in 2011. By the end of August, U.S. production was down from more than 13 MMbbl/d to 9.7 MMbbl/d. And according to Westwood Energent, the number of frac crews in the Permian had fallen to the 18-20 range.

Although the industry has never faced an environment quite like 2020, every downturn is inevitably followed by a recovery. By late October, the rig count slowly climbed to 287, with weekly gains every week since Sept. 11.

Most analysts believe that the rig count as well as the number of frac crews will pick back up in 2021 as companies put their DUCs on production.

Todd Bush at Westwood Energent estimated that for operators to maintain previous production levels, the industry would need to put about 150 frac crews back to work. Trends appear to be moving in that direction.

According to Tudor, Pickering and Holt (TPH), the number of pressure pumping crews increased by as much as 18% from August to September 2020, and another 6% from September to October. In fact, TPH analysts said late last year that if completion activity held through the end of 2020, the active spread count could be up by as much as 24% quarter over quarter.

Certainly the U.S. shale industry took its hits in 2020, with some regions faring better than others. In the following special report, E&P Plus has partnered with Enverus to provide an in-depth analysis of the seven major shale basins—the Permian, Bakken, Rockies, Marcellus/Utica, Haynesville, Eagle Ford and Midcontinent. These “score cards” provide what went well for each shale, what didn’t, the game changer that will push that basin to prosperity, exclusive analyst insight into each basin and a production forecast for what Enverus sees moving forward.

Brian Walzel, Senior Editor
Editor’s note: The analysis, insight and data included in this special report were provided in partnership with Enverus in late October 2020. All charts are courtesy of Enverus.
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bakken unique well pads fractured bar graph
bakken unique well pads fractured bar graph
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The Good
After the 2015/2016 downturn, operators adopted modern completion designs. Proppant intensity increased from 2010-2015 levels at about 300-500 lb/ft to about 900-1,000 lb/ft, while fluid intensity increased from 6-12 bbl/ft to 20-23 bbl/ft during that same timeframe. The new completion design has proven optimal in the basin as operators have not deviated from the design since 2017, and productivity has responded positively.
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The Bad
Although operators in the Bakken have modernized completions, it is still one of the most mature unconventional basins in the country. Accordingly, the number of drillable locations in the core is dwindling. The lack of available inventory in the core will force operators to look into noncore areas for additional locations. Given the current price environment, operators are likely to focus on core acreage, which will diminish the limited core inventory even faster.
THE FUTURE
The Dakota Access Pipeline (DAPL), a 570,000-bbl/d pipeline originating in the Bakken, is a key pipeline that exports Bakken crude to downstream markets. DAPL has faced scrutiny since it has been built, and a judge ordered the pipeline to shut down earlier In 2020. While the order was ultimately overturned and DAPL continues transporting crude oil, the unknown of what may happen in the future is a major concern. Should DAPL be ordered to halt shipping, operators would be forced to move crude by rail, which would have significant impacts on netbacks.
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WHAT THEY’RE SAYING
“The Williston has a clearly defined core, which is easily identifiable by looking at the lower water-to-oil areas. Completion designs have been optimized to modern parameters. While this helps returns, it also limits the upside for the basin as there is little room for efficiency gains. Drillable locations in the core of the basin are limited, especially as operators target their best acreage during the downturn.”
Hakan Corapcioglu
Senior Energy Market Analyst, Enverus
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THE GAME CHANGER
As one of the oldest unconventional basins in the country, older wells did not employ the optimal completion designs that we use today. Given that these wells may have had lower recovery rates, future refrac opportunities exist.
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eagle ford unique well pads produced bar graph
eagle ford unique well pads produced bar graph
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The Good
The Karnes Trough is still one of the most productive and economic areas in the country. In comparison to the northern oil window of the Delaware, the Karnes Trough normalized IP rates outperform by 29% from 2015 through 2018. In 2019 and 2020, the two areas were very similar in terms of normalized oil IP rates. The Eagle Ford hosts one of the most economic parts of the Lower 48, and other parts of the basin continue to screen well in terms of economics in the shale supply stack.
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The Bad
The Eastern Eagle Ford, largely controlled by Chesapeake via the WildHorse acquisition, has been underwhelming when compared to the Western Eagle Ford. Type curves in the Eastern Eagle Ford improved with high proppant intensity completion design, but it still trails its western counterpart. Given that the Eastern Eagle Ford is largely controlled by Chesapeake, which filed for bankruptcy earlier in 2020, development of the area will likely slow.
THE FUTURE
The Eagle Ford can be considered a mature unconventional oil play. Therefore, the number of drillable locations in the core is starting to dwindle. With the expectation that higher gas prices will be required to balance the market in 2021, the southwestern part of the play, where the Eagle Ford gets gassier, will likely see increased activity.
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WHAT THEY’RE SAYING
“In the Eagle Ford, we see increasing interest in technologies like EOR and refracs, which provide operators optionality after primary development opportunities become exhausted. Furthermore, the combined effects of higher 2021 strip pricing and relative ease of market access support economic gas development in the western part of the play.”
Heather Leahey
Senior Associate, Enverus
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THE GAME CHANGER
As one of the older unconventional basins in the Lower 48, the Eagle Ford is running low on top-tier inventory. This has brought an increased interest in refracking wells as well as EOR methods. As older unconventional wells were not completed with the modern completions we have today, refracs or EOR could help increase recovery factors.
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haynesville unique well pads fractured bar graph
haynesville unique well pads fractured bar graph
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The Good
In 2015 nearly 65% of the rigs and about 84% of the natural gas production in the Haynesville came from the Louisiana core. In 2020 (as of late October), only 39% of the rigs and 51% of the production in the basin came from the Louisiana core. Yet, average type curves remain intact, which bodes well for future production. Being near the demand centers and export markets helps the Haynesville in comparison with the Northeast.
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The Bad
The Haynesville is one of the main natural gas basins in the Lower 48, along with the Marcellus and Utica. However, unlike the Northeast basins, the Haynesville is nearly all dry gas production. Only producing dry gas leaves producers susceptible to natural gas prices without the ability to switch to a wet gas or condensate play. As we’ve seen over the last few years, associated gas production has exploded in the Permian, ultimately oversupplying the market and pushing natural gas prices down. Operators in the Haynesville, if not hedged, were vulnerable to those low prices.
THE FUTURE
The COVID-19 pandemic has taken its toll on many different industries, and the oil and gas sector is no different. With crude oil prices down and showing slow recovery, associated gas production will be down in the winter heating season and 2021. This decline in production is expected to cause an upward move in natural gas prices. The Haynesville, with ample takeaway capacity and being a gas-focused basin, will be called upon to help offset the natural gas deficit.
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WHAT THEY’RE SAYING
“In 2016 the Haynesville was sitting below 4 Bcf/d of gas production. Starting in 2017, operators adopted a higher intense completion design, which improved its competitiveness with Appalachia and allowed the play to reach 11-plus Bcf/d in late 2019, with most of the production increase coming from outside the traditional core. With ample takeaway capacity in the Haynesville and the possibility of higher sustained gas prices beyond 2021, some proven private operators, which drove production expansion in the past, will be motivated to initiate public-equity offerings to fund further growth.”
Jimmy McNamara
Senior Intelligence Associate, Enverus
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THE GAME CHANGER
Prior to 2017, the Haynesville was considered a second-tier gas play. However, the adoption of new completion designs in the basin brought it into the first-tier gas play bracket along with the Northeast. Proppant and fluid intensity increased following 2016, and this completion design change has helped the Haynesville look prospective for continued activity in a favorable gas price environment.
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appalachian unique well pads produced bar graph
appalachian unique well pads produced bar graph
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The Good
Longer laterals were drilled in 2020 when compared to 2019, and these longer laterals resulted in better overall 2020 normalized type curves. The core northeast Pennsylvania area saw laterals increase by more than 1,700 ft on average in 2020, and normalized type curves showed IP rates increasing 300 Mcf/d per 1,000 ft compared to 2019.
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The Bad
Infrastructure development has been difficult to get across the finish line. Most projects going north or toward the East Coast face legal battles or permit troubles. Many pipeline projects heading north have trouble acquiring permits, while projects heading toward the Mid-Atlantic have faced legal battles opposing the permits they have received, ultimately resulting in severe delays and cancellations.
THE FUTURE
Core Marcellus and Utica have sub-$2.25/MMBtu gas breakeven prices. With associated gas production down due to crude prices from lagging demand, natural gas prices are expected to climb due to a supply shortfall. Accordingly, the Northeast will be called on to increase supply. MVP, a 2 Bcf/d pipeline taking gas to Virginia, will help in the near term. However, with Mountain Valley Pipeline being the only large pipeline development on the project slate, future production growth will rely on the ability to debottleneck pipeline capacity.
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WHAT THEY’RE SAYING
“After years of Appalachia operators outspending cashflow to chase double-digit growth, a combination of swelling leverage, investor sentiment and egress limitations has driven a point of inflection in one of the lowest-cost gas basins in the Lower 48. With operators pledging to invest within cash flow, near-term growth is limited even at the higher prices expected for 2021, with ultimate growth being capped by restricted spare capacity out of the basin.”
Matt Clenchy
Research Analyst, Enverus
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THE GAME CHANGER
As it becomes increasingly difficult to get new pipelines built to ship gas out of the region, production growth will be capped at takeaway capacity. The game changer in the Northeast could be positive or negative. Should pipeline bottlenecks arise, in-basin pricing will have downward pressure and production will be capped. Should additional capacity hit the market, production growth will be possible and regional pricing will be positively impacted.
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scoop/stack unique well pads fractured bar graph
scoop/stack unique well pads fractured bar graph
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The Good
The SCOOP and STACK normalized oil type curves in 2019 for half or fully bounded wells saw production increases when compared to 2018. Wells in 2019 saw average laterals increase by about 1,100 ft with a slight increase in proppant intensity. This is promising for the SCOOP and STACK that had seen normalized oil type curve degradation since 2016.
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The Bad
After an improvement in normalized type curves in 2019, the SCOOP and STACK saw type curve degradation in 2020. A majority of wells, roughly 38%, in 2020 (as of late October) fall in the STACK Volatile Oil sub-play, most of which started producing in the first quarter. For half or fully bounded wells in the STACK Volatile Oil sub-play, spacing decreased more than 100 ft in 2020 on average, causing a drop in the normalized type curve.
THE FUTURE
The Midcontinent craze that started in 2016 was not able to hold on for long. Operators had an expectation that the basin would continue to provide efficiency gains, but well spacing issues limited that expectation within a couple of years. While well spacing will be an ongoing battle, the core of the SCOOP and STACK remain economic plays for operators in the basin that employ sound spacing and completion optimization.
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WHAT THEY’RE SAYING
“The Midcon continues to be a challenging region to operate economically as seen by the exodus of drilling capital from most of the multibasin operators and cratering rig activity over the last few quarters [in 2020]. Those with the luxury to pivot to other plays have largely sidelined the STACK, while the SCOOP remains the only bright spot with some of the best Lower 48 well results coming out of this play, though scale and repeatability of the resource remains in question. Activity will be slow to rebound in the Midcon for the medium term as the oil price recovery continues to putter.”
Jason Levesque
Senior Associate, Enverus
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THE GAME CHANGER
Spacing has been, and will continue to be, the game changer in the Midcontinent. In 2019 operators had success for the first time since 2016 in achieving year-over-year normalized type curve growth. However, 2020 brought type curve degradation as well spacing decreased.
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permian unique well pads produced bar graph
permian unique well pads produced bar graph
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The Good
While rigs in the Permian have not recovered from the drop following the pandemic, frac crews have picked up in the basin. The Delaware and Midland have been the primary drivers of the uptick in activity. Both plays hit their 2020 low point in frac crew activity in May. From May to September 2020, the Delaware frac activity increased 134%, while the Midland increased 236%.
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The Bad
After years of normalized type curve improvements because of drilling and completion efficiencies, 2020 brought slight type curve degradation to the basin. While fluid and proppant intensity per perforated foot has remained relatively the same, partially or fully bounded wells drilled in 2020 showed less impressive type curve results than those drilled in 2019.
THE FUTURE
While 2020 brought type curve degradation to the Permian, economics in the basin remain some of the best in the country. The buildout of pipeline capacity over the last couple of years will allow commodities to exit the basin and make their way to downstream markets, the majority of which are on the Gulf Coast. The Permian has been the most active and productive basin in the country over the last few years and will continue to play a major role in production growth.
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WHAT THEY’RE SAYING
“While activity is still depressed compared to where it was to start the year, the Permian has picked up quicker relative to other basins from the plunge due to COVID-19. Operators that have large, multibasin portfolios are focusing their spending on the Permian over other basins due to the more favorable economics. Operators will continue to focus on developing their Permian acreage while crude prices recover.”
Bernadette Johnson
Vice President Macro Fundamentals, Enverus
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THE GAME CHANGER
The Permian exploded with production over the last half-decade, and the midstream sector was not able to keep up with providing takeaway capacity at the rate the basin was growing. However, over the last couple of years, midstream players have built crude, natural gas and NGL pipelines, mainly flowing to the Gulf Coast. With the buildout of these pipelines, bottlenecks were relieved in the basin and strengthened in-basin pricing.
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rockies unique well pads fractured bar graph
rockies unique well pads fractured bar graph
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The Good
The Denver-Julesburg (D-J) Basin is the heart of Rockies production. Well costs are low in the play and the core economics are top tier in the Lower 48, with breakevens in the core at sub-$40/bbl. If political risk factors do not hinder operators’ abilities to develop their assets, economics are favorable for activity.
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The Bad
The core of the D-J has been largely consolidated. Two of its biggest operators, Anadarko and Noble, have been acquired by Occidental Petroleum and Chevron, which have larger portfolios where the D-J will have to battle for capex allocation. Adding in the tough regulatory environment, it is difficult to imagine the new owners focusing in the D-J, like Anadarko and Noble used to.
THE FUTURE
The future of the Rockies is largely dependent upon political risk and how stringent regulations become, particularly in Colorado. More regulation in Colorado for the oil and gas industry has been a factor over the last few years, and it is likely not going anywhere in the future. Operators with large, multibasin portfolios may avoid spending capital in the region in favor of other basins due to the regulatory climate. Outside of Colorado and the D-J, the Powder River Basin has seen normalized type curve degradation over the last few years, while the Uinta struggles to find markets for its crude quality. As long as the crude markets are in recovery from the pandemic, operators will focus on their core acreage in the Rockies.
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WHAT THEY’RE SAYING
“D-J is the Rockies basin with the most top-tier inventory, but political circumstances are souring the outlook for its development potential. The Powder River Basin has struggled to breakout, and mixed results in a low-price environment isn’t desirable for operators with other options in their portfolio. Despite promising results in the Uinta, doubts remain around the areal extent, which can be exploited horizontally, not to mention the limited buyer for its production due to quality issues with its oil production.”
Sarp Ozkan
Senior Director of Energy Analytics, Enverus
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THE GAME CHANGER
The state of Colorado, home to one of the Rockies best plays in the D-J, has proposed new regulations that would require new well pads to be 2,000 ft away from building units and school properties. This is an increase from the current setback of 500 ft. The Colorado Oil and Gas Conservation Commission (COGCC) has provided outlets for operators to drill within that 2,000-ft setback. However, the burden of proof will fall on the operators to convince the COGCC to approve the permits.