September 2022
Mid-Year Forecast & Review

U.S. drilling to surge as operators prepare to take advantage of higher crude prices

The loss of Russian crude supplies and the lingering effects of Covid-19 have driven oil prices to multi-year highs. U.S. operators have shown restraint, but according to World Oil’s mid-year forecast, a further activity increase is in the offing.
Craig Fleming / World Oil Kurt Abraham / World Oil

The war in Ukraine has limited Russian oil and gas supplies and has the potential to cause a major shift in the world’s energy market. No one knows how long Russia intends to wage war in Ukraine or how much of its crude will be affected by sanctions or for how long. The uncertainty caused by the supply disruption has driven crude prices to multi-year highs. And anxieties persist that surging oil prices may rise so high that demand destruction will damage the global economy and cause a worldwide recession. However, Russia’s invasion of Ukraine is creating a new market for U.S. LNG producers, as product flows to Europe to replace Russian natural gas. The longer the conflict persists, the more entrenched U.S. LNG will become. 

Fig. 1. Drilling activity in the U.S. increased steadily through the first seven months of 2022, but the rig count slowed and began to plateau in August and September. Image: Pioneer Natural Resources Company.

ESG impact. Although the U.S. petroleum industry faces continued pressure from President Biden and environmental groups about the imperative of reducing fossil fuel usage to slow GHG emissions, the drive for rapid implementation has lessened. However, the transition to renewables and clean energy alternatives has created an unprecedented reduction of investment in hydrocarbon-based energy, in favor of developing green resources. During 2021, global oil and gas discoveries hit their lowest level in 75 years. Total global discovered volumes in 2021 were calculated at 4.7 Bboe, the lowest tally since 1946. This trend is predicted to continue in 2022. A data-based comparison shows a significant reduction in recoverable oil resources that will drive commodity prices higher and further damage global energy security. 

U.S. production surges. Despite a sizeable drop in recoverable resources, U.S. oil production remains on track for a record in 2023, even as output grows more slowly than anticipated amid increased costs and labor shortages in America’s shale fields. Output is expected to expand at an average 840,000 bopd next year, down from a prior forecast of 860,000 bopd, according to the EIA. While production is still seen reaching an all-time high in 2023, the government revised its forecast slightly lower to 12.7 MMbopd. The current, annual, U.S. record average is 12.3 MMbopd, set in 2019. 

At the start of the year, production in the U.S. (11.7 MMbopd), Saudi Arabia (10.2 MMbopd) and Russia (11.0 MMbopd) was running at nearly full capacity. Brent and WTI were trading at $86.51/bbl and $83.22, respectively. When Russia invaded Ukraine on Feb. 24, 2022, the EU and international community reacted quickly by boycotting Russian supply. The embargo quickly pushed prices up, and in June, Brent was trading for $122.71/bbl and WTI hit $114.84/bbl, the highest price since August 2008. Prices retreated in July, down to $111.93/bbl for Brent and $101.62/bbl for WTI, due to rising interest rates and fear of economic recession, despite restricted Russian supply. 

Table 1. Mid-year revision, 2022 U.S. drilling forecast

Demand to lessen. The global surge in the cost of fuel is starting to weigh on demand, according to Vitol Group, the world’s largest independent oil trader. Consumers are being impacted by the run-up in gasoline, diesel and other oil products said Mike Muller, head of Vitol Asia. There is clear evidence of economic stress being caused by high oil and natural gas prices, according to Muller. 


The Baker Hughes rotary rig count stood at 588 units during the week ending Jan. 7, 2022. U.S. drilling activity climbed steadily for the next seven months, although it slowed in July and August, reaching 760 in the week ending Sept. 2, Fig. 1. Although the 172-rig increase represents a Jan.-Sept. increase of 29%, U.S. shale operators have resisted ramping-up drilling activity and remained relatively disciplined with their capital expenditures. The speed at which new rigs have been deployed to the field is considerably less than in previous up-price cycles. Most U.S. shale companies are still being conservative, as priorities remain focused on protecting balance sheets and generating free cash flow. 

This conservative approach, along with high oil prices, has enabled shale companies to reduce their debt burdens in the second quarter, signaling room for them to pay dividends, buy back shares or make acquisitions. A metric commonly used to measure companies’ ability to pay down their borrowings has widely improved among oil and gas producers, as they repurchase some bonds and pile up cash amid ballooning profits. 

Net debt reported by a group of independent operators, including ConocoPhillips and Pioneer Natural Resources, averaged less than 0.6 times their annual earnings before items such as interest and taxes in the second quarter, down from 1.7 times a year earlier. Many companies have reached their debt target. Energy companies have made great strides toward repairing and reinforcing their balance sheets and are in a much stronger position to handle another downturn in commodity prices. 

With WTI trading between $85/bbl and $95/bbl, U.S. shale producers are on course to generate $200 billion this year, enough to make the industry debt-free by 2024 and potentially fund a pivot toward more natural gas production (Deloitte). High oil prices and disciplined capital spending mean U.S. shale producers are on track for their most profitable year on record, part of a global trend that will see the oil and gas industry generate a record $1.4 trillion of free cash flow. After paying down debt and rewarding shareholders, U.S. producers will likely focus more on natural gas production, due to high demand and prices around the world. Producers will also make record profits from U.S. LNG operations. They are expected to generate $59 billion this year, double last year’s amount and easily recouping the $45 billion of losses from 2013 to 2020. 

Fig. 2. As shown in this all-time U.S. drilling chart, activity for the last two years has grown slowly but steadily since bottoming out during 2020. If the forecast holds, U.S. drilling will be up nearly 50% in 2022, compared to the low point two years ago. Chart:©World Oil.


Due to sustained higher oil prices, World Oil forecasts a noticeable uptick in drilling activity for the remainder of the year, projecting 18,600 total wells for 2022—a 34% increase from the 2021 count of 13,877, Table 1. Total footage is projected to increase from 191.5 MMft in 2021 to 256.4 MMft in 2022—an increase of 34%. During 2022, 8,769 wells are estimated to have been drilled during the first six months, while 9,831 are expected to spud in the second half of the year, for a half-to-half increase of 12.1%. A 14.9% increase in footage is expected in the last six months. 


Oil prices have been rising since the start of 2021, bolstered by restricted Russian supplies and recovering demand. However, upstream M&A activity, which typically follows oil prices, remains well below pre-pandemic levels. The total count and value of U.S. upstream deals during the first eight months of 2021 were down 30% and 46%, respectively, from the same period in 2019. 

While the ongoing capital discipline of operating companies is the primary reason behind the slowdown in upstream M&A activity, limited visibility of buyers into the carbon profile of sellers’ assets is a growing factor. Companies pursuing their net-zero goals are either looking to acquire low-carbon-intensity barrels or divest the high-intensity ones, implying that there might be an acreage consolidation or portfolio restructuring on the horizon (Deloitte). But a large resource size and an attractive offering price may not be enough to elicit a response from a buyer focused on meeting its net-zero targets. Therefore, M&A activities would need not only to be financially accretive, but also to support ESG goals. 

Devon Energy agreed to acquire Validus Energy for $1.8 billion in cash, to expand in the Eagle Ford shale play in South Texas. The deal will add to Devon’s cash flow and earnings in the first year, and boost its variable dividend by up to 10%, based on current oil futures prices. Devon also said the transaction will enable the acceleration of the return of cash to investors via its existing $2 billion stock buyback program. Buying Validus will add 42,000 net acres adjacent to Devon’s existing leasehold in the Eagle Ford. Validus’s production is approximately 35,000 boed, with volumes expected to increase to 40,000 boed over the next year. 

EQT to buy Marcellus assets. EQT Corp, the largest U.S. natural gas producer, agreed to acquire THQ Appalachia, a privately held company, in a $5.2 billion deal to expand holdings in the Marcellus shale. The company purchased the assets from Alta Resources for $2.9 billion. It also acquired Chevron’s assets in Appalachia for $735 million in 2020. THQ Appalachia produces nearly 800 MMcfgd in West Virginia. The company has about 11 years of inventory at maintenance capital levels. EQT is expected to produce the equivalent of 5.5 Bcfd this year. 


Fig. 3. Drilling levels in the U.S. Gulf of Mexico will be up about 8.5%, compared to 2021’s activity. Second-half 2022 drilling will be up only slightly from the first half. Image: Transocean.

Heading into 2022, most operators expected pricing to increase for nearly all service lines but seismic. Labor, tubulars, fracturing/stimulation, and transportation were the areas of greatest concern. A modest 15% expected pricing to remain stable, including nearly 39% for completion equipment, 35% for other services, and 33% for drilling. Further pricing concessions were expected by a modest few for seismic services and tubulars. 

Further pricing increases are expected in the second half of 2022, with limited availability of OCTG and casing potentially curtailing spending revisions. Overall spending in OFS is expected to remain about 25% below 2019 levels until 2025. With margins at the mercy of another price cycle and reduced spending, many OFS companies are crafting a new strategy for the future of energy. With a broadening decarbonization mandate across industries, companies have an opportunity to lead the way for customers by fully re-engineering traditional OFS business models and solutions outside the traditional oilfield services and to other industries. 

Many large service providers have diversified beyond core services. One large company has restructured its business by launching cloud and edge computing services, whose rate of growth is expected to outpace that of their O&G business in a few years. Similarly, Halliburton and Baker Hughes are partnering with start-ups and academic institutions, through their Halliburton Labs and Baker Hughes Energy Innovation Center, respectively, to accelerate technology development for diverse energy and industrial applications. 

However, digitalization will only help to a certain extent. Providing integrated solutions for decarbonizing upstream projects, implementing subscription-based revenue models or diversifying into the low-carbon space, such as hydrogen and CCUS, are key to future growth. 


The number of licensed blocks and total acreage fell to near all-time lows, as the sector struggles to shake off the effects of the Covid-19 pandemic and the ensuing oil market crash (Rystad). Only 21 leasing rounds were completed globally through August this year, half of the 42 rounds held in the first eight months of 2021. The acreage awarded so far this year has shrunk to a 20-year low of 320,000 km2. Global leasing rounds are expected to total 44 this year, 14 less than in 2021 and the lowest level since 2000. 

Global spending on exploration has been falling in recent years, as oil and gas companies seek to limit risk by focusing on core producing assets and regions with guaranteed output, aiming to streamline their operations and build a more resilient business amid market uncertainty and the threat of a recession. The political landscape is also contributing to the decrease in license awards, with many governments pausing or halting leases and encouraging companies to wrap up exploration activity within already awarded blocks. This trend is likely to continue, as governments are less eager to invest in fossil fuel production and instead look ahead to a net zero future. 

The onshore exploration sector is a significant contributor to the decline in awarded acreage. Total onshore acreage awarded in leasing activity has plummeted from more than 560,000 km2 in 2019 to a mere 115,000 km,2 so far this year. Offshore leased acreage hit a high point in 2019 before dropping off a cliff in 2020 and has remained relatively flat in the past two years. Concluded leasing rounds have dropped significantly in the U.S., driven primarily by the cancellation of Lease Sales 259 and 261 in the Gulf of Mexico and Cook Inlet in Alaska. 


Employment in the U.S. oilfield services and equipment sector rose by an estimated 6,865 jobs to 648,914 in August, according to data from the Bureau of Labor Statistics and analysis by the Energy Workforce & Technology Council. Gains in August make OFS employment the highest since the Covid-19 pandemic began, but they are still off the pre-pandemic mark in February 2020 of 706,528. Overall, U.S. employers added 315,000 jobs, down from July numbers but still representing a strong pace of growth.

Fig. 4. Symbolized by this picturesque wellsite close to Signal Peak bluff in the Midland basin, near Big Spring, Texas (Howard County), drilling in the Permian region is at its highest level since 2019. Image: Latshaw Drilling Company.



North American spending is forecast to increase 33% from 2021 levels, which is an acceleration from 20.6% growth projected in a December survey and builds on the modest 1% increase experienced in 2021, according to James West, senior managing director at Evercore ISI. The increase is driven by a 1,260 bps acceleration in the U.S. to 36% growth, which more than offset a 2.8% decline in spending in 2021 excluding the historical capex of distressed companies that have since been acquired or privatized. Private and independent operators are leading the recovery, with capex accelerating by 1,440 bps and 1,550 bps from the December survey to 56% and 42%, respectively, and also accelerating from 41% and 5% growth in 2021. More modest growth of 25% and 19% are anticipated from the majors and NOCs, both of which contracted further in 2021. 

While the majors have more than offset declines in 2021 despite recent divestitures—with Evercore’s projected 2022 spending nearly 7% above 2020 levels—spending from the NOCs remains 25% lower, to account for less than 1% of total U.S. spending (vs. almost 2% in 2020). Overall, the majors account for almost 30% of U.S. capex, down from 36% in 2020, while the independents, including privates, account for 70% of all spending, up from 62%. U.S. capex is on track to recover within 25% of pre-pandemic levels and approach levels last seen in 2009 before the start of the oil shale revolution. 

There could be modest upside to NAM spending in in the second half of 2022, with current spot prices above the $84/Bbl WTI and $5.18/MMbtu HH average basis for establishing 2022 budgets. While half of survey respondents would maintain their budget, regardless of changes in the oil and gas price, one-third are willing to flex capex higher for rising cash flow. However, Evercore believes upside is likely to remain muted, as activity could be constrained by the availability of goods, services and labor. 

Operators have been highly disciplined over the past year, as commodity prices increased. Yet, a new round of consolidation may drive spending higher, if commodity prices stabilize at a significantly higher range and confidence in the duration of the cycle increases. From a lower base, Evercore believes the set-up is positive for growth in 2023 and beyond. 


The EIA’s Short-Term Energy Outlook, published September 2022, reports that STEO is subject to heightened uncertainty resulting from Russia’s full-scale invasion of Ukraine and how sanctions affect Russia’s oil production. Also contributing to uncertainty is the production decisions of OPEC+, the rate at which U.S. oil and natural gas production rises, and other contributing factors. Less robust economic activity in the STEO forecast could result in lower-than-expected energy consumption. 

Oil price forecast. Russia’s full-scale invasion of Ukraine has resulted in shifting trade patterns, leaving Europe to find substitutes for Russia’s oil. This change has driven up the price of Brent contracts to a level high enough to reduce Asia’s imports of Brent and to retain more oil in Europe. EIA forecasts the spot price of Brent crude will average $98/bbl in the fourth quarter of 2022 and $97/bbl in 2023. The possibility of petroleum supply disruptions and slower-than-expected crude oil production growth continues to create the potential for higher oil prices, while the possibility of slower-than-forecast economic growth creates the potential for lower prices. 

Fig. 5. With plenty of drilling occurring in North Dakota during the last 12 to 15 years, and many wells like this one put onstream, there is a concern that the Bakken’s sweet spot has reached maximum infill development. Image: ConocoPhillips.

Crude production forecast. U.S. crude oil production is forecast to average 11.8 MMbopd in 2022 and 12.6 MMbopd during 2023, which would set a record for the most U.S. oil output during a year. The current record is 12.3 MMbopd, set in 2019. 

Natural gas prices. In August, the Henry Hub spot price averaged $8.80/MMBtu, up from $7.28/MMBtu in July. Natural gas prices rose in August because of continued strong demand for natural gas in the electric power sector, which has kept natural gas inventories below their five-year (2017–2021) average. EIA expects HH price to average $9/MMBtu in in the fourth quarter of 2022 and then fall to an average $6/MMBtu in 2023, as U.S. natural gas production rises. 

Natural gas production. Dry natural gas production has been rising relatively steadily since the first quarter of 2022, when it averaged 94.6 Bcfd. EIA forecasts U.S. natural gas production to average 99.0 Bcfd during fourth-quarter 2022 and then rise to 100.4 Bcfd in 2023. 


Given the restricted Russian supply, demand recovery and resulting increase in crude prices, operators working the various U.S. plays plan to noticeably increase drilling activity for the remainder of 2022. Overall, activity in the Texas shale plays will improve in the second half of the year, with the exception of District 7B, District 8 and District 8A, which will suffer slight second-half losses. However, drilling on the Texas side of the Haynesville is projected to improve 26% on a y-o-y basis. Gulf of Mexico activity will increase 8.4%, but a decline of 70% is forecast offshore California, both on a y-o-y basis. 

Gulf of Mexico. Higher oil prices should help boost activity slightly in the GOM, and it appears that offshore operators are poised to resume limited development in 2022-2023 after last year’s decline, Fig. 3. World Oil’s survey results and federal officials’ predicted well counts show a slight increase during second-half 2022. World Oil forecasts that GOM activity totaled 63 wells in the first half of the year, with another 65 scheduled to be drilled during second-half 2022. The projected 128-well total will be 8.4% higher than 2021’s figure of 118. Footage drilled should be up 6.6% on a y-o-y basis. 


Texas. Most of the shale plays in the Lone Star State are gaining ground during 2022. On a half-over-half basis, World Oil predicts Texas wells will gain 11.6%, with the 2022 total being 39% more than the 2021 figure. In the Permian basin (Fig. 4), District 8 will be up 8% in the second half, buts its total will be 26% higher than wells drilled in 2021. Districts 7C and 8A will enjoy much-improved drilling activity, with gains of 33% and 172% respectively, compared to their 2021 totals. 

The Eagle Ford forecast is also good, with District 1 forecast to improve 30% in the second half and up 64% on a y-o-y basis. District 2 will experience a 4% gain in activity in the second half, and is also projected to be up 26% on a y-o-y basis. District 4 in the Eagle Ford will experience a 47% increase between the two halves and post a massive 157% gain from 2021’s level. The reason that District 4 is surging is more gas-related activity. Of the 12 Railroad Districts, 10 are forecast to experience gains, with only two losing ground on a half-over-half basis. Again, more gas drilling is a factor, especially in RRC 6, with the Haynesville up 36% y-o-y. 

DUC wells decline. According to EIA’s July 2022 tally, the DUC total stood at 4,277, a reduction of 1,680 wells since July 2021, a reduction of 28%. In the Permian basin, operators have completed 1,092 DUC wells during the July 2022-July 2021 interval, a reduction of 48%. All other regions declined too, with the exception of the Haynesville, which added 80 DUC wells up to 477, a y-o-y increase of 20%. 

Oklahoma. Although the SCOOP and STACK plays are not as prolific as the Permian or Eagle Ford, acreage in Kingfisher, Canadian, Blaine, and Grady counties continues to attract interest for hydrocarbon development. But the region’s inconsistent geology and less-than-ideal shale formations have produced unpredictable results, reducing ROI. However, with higher oil prices, the plays have become more attractive, and we predict a major increase in Oklahoma’s activity. World Oil forecasts companies will drill 79% more wells in 2022 than last year’s total. Total footage will also surge forward 75%, with operators making 15.7 MMft of hole. 

Louisiana. In the state’s northern portion, we forecast operators developing Haynesville shale gas will drill 25% more wells in 2022, than they did in 2021, with total footage up approximately 17%. With natural gas prices at near-record highs, the increase in activity could continue, similar to the Haynesville play in Texas RRC District 6. Despite near-record high natural gas prices, DUCs in the Haynesville were up to 477 in July, a jump of 20%. In the mature, shallow oil plays of southern Louisiana, we expect operators to drill 46% more wells compared to last year. Well footage is expected to increase 29% on a y-o-y basis. 

Fig. 6. Drilling activity in the Marcellus shale of the northeastern U.S. continues to improve. Image: CNX Resources Corporation.

North Dakota. The Bakken is running out of steam. Although transportation issues remain a challenge in this oil-rich shale play, a greater concern is that the sweet spot has reached maximum infill development, Fig. 5. However, higher oil prices will help negate the cost of drilling the 21,100-ft wells. Considering these factors, along with data from state officials and World Oil operator surveys, we forecast that drilling will be up a disappointing 4%, with footage increasing 2.9%, y-o-y, in the Peace Garden State. 

Northeast (Pa./W.V./Ohio). In the Northeast, Marcellus activity is on an upward trend, similar to other U.S. shale plays, Fig. 6. Improving natural gas prices and increased LNG exports from Dominion Energy’s massive Cove Point facility are helping drive activity higher in the region. According to survey results, operators tapping the high-quality reservoir in Pennsylvania will increase the number of wells drilled this year by 18%, compared to the number drilled in 2021. Total footage for 2022 is forecast to jump 16.5%. 

In Ohio, operators working the Utica play plan to focus on growth and capitalize on higher gas prices, with this year’s total well count expected to finish 30% higher than last year’s level. Footage is forecast to increase 31%. In West Virginia, World Oil forecasts operators will drill 84 more wells than the number spudded in 2021, up 62%. We also forecast a 64% surge in total footage in the Mountain State. Despite surging gas prices, operators working the shale fields of Appalachia were able to reduce the region’s DUC count by only eight wells in July on a y-o-y basis, a reduction of just 11%. 

Midwest (Illinois/Kansas). There are approximately 32,100 oil and gas wells, 10,500 Class II injection wells and 1,750 gas storage wells producing from 650 fields in Illinois. These wells are controlled by 1,500 operators. There is oil production in 40 of the 102 counties, mainly in the southern part of the state. Drilling will surge, with a 61% increase in wells forecast for 2022, compared to 2021’s level. Although the wells are relatively shallow, they provide work for the oilfield community and the drilling crews. We forecast a 59% jump in total footage. 

In Kansas, much of the shallow drilling in the Hugoton basin appears to stay below the Baker Hughes rig count radar. But according to the Kansas Corporation Commission, drilling in the Sunflower State is projected to increase 24% in 2022, compared to the 1,005 drilled in 2021. Total footage is forecast to jump 24%. 

Rocky Mountains. The Denver Julesburg basin has experienced a constant decline since production peaked in November 2019. Reversing this trend will depend on the capital allocation from major operators in the region. The DJ basin accounted for 7% of oil and 6.6% of natural gas production in the Lower 48 in 2021 (GlobalData). While other U.S. basins have increased their rig count with the rise in commodity prices. Operators, like Oxy and Chevron, are earning better returns from investments in other basins, but could grow production in the DJ by completing their DUC backlog. 

In Colorado, officials continue to attempt to ban, or severely limit, drilling in the state. In 2019, the state passed Senate Bill 118, “which fundamentally altered the oil and gas industry’s future in the state,” according to Colorado Governor Jared Polis. However, it appears companies intend to push back and continue operations on existing leases, as World Oil expects operators in Colorado to drill 40% more wells in 2022, compared to activity during 2021. Total footage is projected to increase by 40% on a y-o-y basis. 

In 2019, a federal judge ordered a halt to exploration on 300,000 acres in Wyoming, saying the government must account for its cumulative effect on climate change. The ruling came in a lawsuit filed by a pair of environmental groups, challenging the BLM’s decision to lease federal lands for energy development in the state. Given that nearly 50% of all lands in Wyoming are owned by the federal government, a ban on federal leasing would decimate the natural gas industry and Wyoming’s economy. Despite the ongoing lawsuit, operators working in the state plan to increase drilling activity by 24% in 2022. World Oil predicts footage will increase 25%. 

Canadian Overseas Petroleum received a resource report prepared by Ryder Scott that confirmed its deep oil discovery on lands in Converse and Natrona counties, Wyoming. The report confirms the deep discovery has total original oil in place of 993.5 MMbbl. This supports the company’s conclusion that the Frontier 2 and Dakota discoveries are large stratigraphic oil accumulations encompassing the reserves at the company’s Cole Creek field. The report outlines 118 horizontal well locations to exploit the identified Frontier 2 and Dakota reserves. COPL plans to drill one Frontier 1 well and two horizontal Frontier 2 wells as part of its 2022-2023 drilling campaign, commencing in fourth-quarter 2022. 

Acreage in New Mexico has become as desirable as land on the Texas side of the Permian basin. Increased completion efficiencies in the Bone Springs formation will help support activity, as drilling in the Land of Enchantment is forecast to increase 23% on a half-over-half basis and 30% y-o-y for 2022. Total footage will increase 33% y-o-y. 

In California, we expect onshore operators to spud four fewer wells in 2022, compared to 2021. But with no new discoveries, operators working the Golden State are forced to survive by maintaining less-attractive heavy oil fields and residual acreage from long-ago discoveries. However, considering the mature nature of these fields, onshore footage is forecast to climb 15% (y-o-y), suggesting deeper total depths as operators squeeze out more oil from these old fields. Drilling offshore California will drop dramatically, with only three wells expected in 2022, a y-o-y decline of 70%. Accordingly, footage is forecast to drop 65%. 

In Alaska, the U.S. DOJ filed a brief defending the Willow project, an energy development within the NPRA on Alaska’s North Slope that has been halted by litigation. The Biden administration announced it would review the Willow plan, approved in 2020 by the Trump administration, for consistency. The project is proposed by ConocoPhillips, and if approved, the project will provide 100,000 bopd, $10 billion in revenue for state, local and federal governments during its lifespan, 2,000 construction jobs, and 300 permanent jobs. It appears the prospect of opening new acreage is having the desired effect. Offshore work will surge 109% in 2022, 12 more than spud in 2021. Onshore activity on the North Slope is projected to increase 67%, with total footage up 67%. 

Others. Activity in non-core producing states will also enjoy a jump in activity. Drilling will increase on a y-o-y basis in Alabama, Arkansas, Montana, Nebraska and New York.  

About the Authors
Craig Fleming
World Oil
Craig Fleming
Kurt Abraham
World Oil
Kurt Abraham
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