U.S drilling: U.S drilling activity to climb as supply disruption continues
The industry has experienced multiple crude price swings over the last seven years, from $100/bbl in 2014 to minus $37/bbl in 2020, to $122/bbl in June 2022. However, today’s energy environment is significantly different from historical boom-bust cycles. Unrealistic clean energy goals, forced on producers by government officials and environmental groups, caused an unprecedented reduction in oil and gas investment at the start of the Covid pandemic. The pressure tactics compelled energy producers to commit to emission-reduction targets and increased investment in cleaner energy, even as they were struggling with massive losses caused by plunging demand.
This, combined with supply issues exacerbated by the war in Ukraine, have created a unique set of economic, geopolitical and trade policies that have triggered significant disruption in the broader energy market. The interruption of energy trade between Europe and Russia has driven global natural gas markets to new highs, reaching six to ten times U.S. Henry Hub (HH) prices. U.S. energy producers must now concentrate on delivering a balanced energy solution, energy security, and supply diversification, while facilitating a low-carbon transition.
Additionally, the shortage of agricultural products for renewable fuels and supply chain challenges for low-carbon technologies have hindered the progress of the energy transition. Although the immediate impact of this imbalance is high energy prices and record cash flows, the industry must determine how, and where, to invest for highest ROI, while delivering regional energy security.
ESG FOCUS FADING
During second-half 2022, oil and gas executives were speaking less about climate change and carbon emissions, indicating that the industry’s public focus on ESG is fading, according to an analysis of quarterly conference calls held by 172 U.S. oil and gas companies. The data show the frequency of terms like climate change, energy transition and net zero are down 40% from the peak levels in 2021. Industry executives “are gleeful that the world is admitting they need fossil fuels.” It’s an “I told you so” moment for the industry, said Jim Murchie, CEO of Energy Income Partners. Hess Corp CEO John Hess said that global policymakers “need to get a dose of reality and realize that we need more investment in oil and gas to have an affordable, just and secure energy transition.”
Upstream recovering. Oil and gas operators staged a remarkable recovery in 2022, Fig. 1. Record cash flows restored confidence and repaired balance sheets. The realization by governmental authorities that renewables are not a near-term solution, and that CCUS is the best path forward, will help drive activity in 2023, and enable accelerated development of low-carbon technologies.
Global E&P spending is poised to increase, in both North America and internationally, for a second straight year in 2023. Excluding Russia, spending is accelerating for a third straight year internationally, while NAM slows after near-record growth in 2022. With energy security, surety of supply and production capacity additions as key drivers for cyclical spending growth, service availability is becoming a real source of concern.
Further increases in service pricing are expected in 2023, with operators anticipating higher pricing for fracturing/stimulation, drilling and completion equipment. Subsurface completion and production, as well as enhanced oil recovery, are areas in need of greater technology innovation, with operators more likely to test and adopt new technologies while the growing interest in ESG appears to be peaking.
Some companies are beginning to increase capex allocations to renewables and low-carbon resources, with some also willing to pay more for a service or technology that lowers carbon emissions. Some analysts are convinced that traditional oil and gas companies will be fundamental to the success of the energy transition and are encouraged by a confluence of events that are driving digitalization of the oil field and the energy transition.
High prices to accelerate energy transition. High commodity prices and growing concerns over energy security are creating urgency for some companies to diversify supply and accelerate low-carbon technologies. As a result, clean energy investment by O&G companies has risen by an average 12% each year since 2020 and is expected to account for an estimated 5% of total capex spending in 2022. That’s up from less than 2% in 2020 (Deloitte).
Supportive policies, in combination with higher cash flows during 2022, have enabled companies to increase investment in clean energy:
- The U.S. passed the Infrastructure Investment and Jobs Act and the Inflation Reduction Act between 2020 and 2022. Together, these provide for $450 billion of clean energy and related investments. The U.S. SEC has proposed rules mandating the disclosure of emissions for companies in their filings. If finalized this year, some of these rules could be enacted in 2023.
- The European Commission passed the Fit for 55 climate package and Europe’s REPowerEU plan. Together, the committed provisions for the clean energy transition and emissions reduction total €300 billion.
Investment should continue increasing in 2023. However, when asked what factors would enable increased investment in clean energy, 30% of respondents selected higher demand for low-carbon clean energies, and 24% selected more scalable and economical low-carbon use cases. This indicates an acceleration of clean energy investment may require more time for demand to develop and technologies to mature.
Digital transformation. While digital technologies, including advanced data analytics, AI/machine learning and remote operations, continue to trail shale-driven fracturing/stimulation and horizontal drilling technologies in impacting 2023 spending plans, analysts expect these technologies to increase in importance over the coming years. Operators are more likely to test and adopt new technologies than a year ago, with a near-record 28% slightly trailing the 30% record set in 2020. And with a lengthening upcycle, operators appear more willing to test new technologies in 2023.
The abovementioned factors, along with World Oil’s surveys of operators and state agencies, have all shaped this cycle’s U.S. forecasting process. Accordingly, World Oil’s editorial staff presents its 2023 E&P forecast, as follows:
- U.S. drilling will increase 8.2%, to 20,655 wells, Table 1
- U.S. footage will increase 8.7%, to 289.4 MMft of hole
- U.S. Gulf of Mexico activity should improve 12.7%, to 142 wells.
U.S. MARKET FACTORS
Capex. Building on strong growth in 2022, NAM is expected to increase 18% during 2023 to within 7% of pre-Covid levels, says James West, senior managing director at the Evercore investment firm (see the feature article on Capital Expenditures). The U.S. should lead again, with spending up 19% in 2023, while Canada moderates at 10.5%.
Independents and private operators have an outsized role in North America, accounting for more than 70% of regional capex. While privates were faster to increase capex post-Covid, the publicly traded independents shored up their balance sheets and prioritized returning cash to shareholders. We believe this trend could be reversing, with privates becoming more fiscally minded as service cost inflation begins to rise.
Private companies make up about 20% of U.S. capex estimates, but 60% of the rig count (Fig. 2), suggesting overall U.S. spending could be larger than estimated. Directionally, the sample of private operators increased U.S. capex by 67% in 2022, accelerating from 56% in a mid-year survey and topping overall growth of 48% from independents. However, private operators are planning to increase spending by a comparable 20% in 2023, in-line with independents’ 22%.
Slower growth of 11.5% and 14% is expected from the majors in the U.S. and Canada, respectively, where they make up less than 10% of spending. If oil and gas prices hold at current levels, 2023 NAM capex is at risk of slipping below initial estimates. At the current 17% rate, it would take five additional years for NAM capex to recover to its 2014 peak. The U.S. could recover to its 2014 peak in four years at an 18% CAGR, in line with projected 2023 growth, while Canada would need 12 years at an 11% growth rate.
Crude production in the U.S. and Russia was relatively stable on a y-o-y basis, but Saudi Arabia assumed its traditional role as swing-producer during 2022. Saudi Aramco increased its output 14% in 2022, averaging 10.5 MMbopd, compared to 9.2 MMbopd in 2021. The U.S. managed to up its output by 770,000 bopd in 2022 to 11.9 MMbopd, compared to 2021, an increase of 7%.
Despite sanctions on Russian crude, the Kremlin managed to crank out 10.26 MMbopd in 2022, which is 151,000 bopd more than averaged in 2021. Russia did take a noticeable hit during the last four months of 2022, averaging just 9.8 MMbopd, as sanctions finally started to take hold. The EIA is projecting that U.S. output will grow 4.2%, to average 12.4 MMbpod in 2023.
Crude price. Oil price expectations have moderated since mid-year 2022, with companies lowering their WTI oil price assumption 7% from $84/bbl to $78/bbl. On average, E&Ps are predicting a WTI oil price above the current spot price but below the Evercore forecast of $84/bbl for 2023.
Oil prices fell below $76/bbl at the start of the year but spiked at $124/bbl in March with the start of the Russia-Ukraine war. The 2022 average WTI price was $95/bbl, which is above pre-Covid levels and closer to prices last seen in 2014 before OPEC’s pivotal “no cut” decision kicked off the multi-year downturn.
Analysts expect oil prices to trend slightly higher from current spot levels and are more bullish, with China reopening in 2023 and the end of SPR releases. EIA forecasts Brent will average $83/bbl, with WTI trading at $77/bbl. It appears the industry is in the midst of a steady up-cycle driven by constructive fundamentals on both the demand and supply sides of the equation.
Natural gas production. EIA forecasts that U.S. production of dry natural gas will average 100
Bcfd from December through March, down about 0.5 Bcfd from November, due to weather-related declines, usually caused by freeze-offs and the possibility of extreme winter weather events. Dry natural gas production increased in 2022, averaging 100 Bcfd in October and November and exceeding pre-pandemic monthly production records from 2019. Growth in natural gas production was driven by increased drilling activity in the Haynesville region and in the Permian basin. Recent pipeline infrastructure expansions in both these regions facilitated the increases in output.
Natural gas price. Henry Hub spot prices averaged $6.42/MMBtu in 2022, due to increased demand for U.S. LNG in Europe. But after reaching a crescendo of $8.81 MMBtu in August, prices plummeted $3.28/MMBtu to just $5.53/MMBtu in December, due to a warmer-than-anticipated winter in the U.S. and Europe. EIA expects HH natural gas spot price to average $5.00/MMBtu during first-quarter 2023. The HH price began January below $4.00/MMBtu as a result of warmer-than-normal temperatures across much of the U.S. However, EIA expects that prices will rise back above $5.00/MMBtu, especially as LNG exports from Freeport LNG resume, increasing demand for natural gas.
Extreme weather events cause price spikes and volatility at both the HH and in regional markets. Spot prices surged in some Western markets in December, and potential natural gas supply constraints in New England could cause large price increases if extreme cold weather hits the region. Based on recent press releases from Freeport LNG, EIA expected the facility to resume partial operations in January, which would increase U.S. LNG exports and put upward pressure on prices. However, federal regulators did not give approval for a re-start until Feb. 21.
LNG outlook. EIA forecasts U.S. natural gas exports to increase in 2023. LNG exports peaked during first- half 2022, as facilities operated close to maximum capacity, and a new facility, Calcasieu Pass, came online and steadily increased output in 2022. However, a fire at Freeport LNG in June resulted in the shutdown of the facility, removing about 2.0 Bcfd of U.S. LNG export capacity during second-half 2022. The Freeport facility announced plans to come back online and to increase output to about 2.0 Bcfd.
When Freeport LNG resumes, EIA forecasts U.S. LNG exports will establish a new record close to 12.5 Bcfd. EIA predicts LNG exports will then reach 12.7 Bcfd by the end of 2023. As no new U.S. LNG export facilities are scheduled to come online during 2023, EIA forecasts U.S. LNG exports will average 12.3 Bcfd throughout 2023, as facilities continue to operate at maximum capacity to meet high demand for natural gas in Europe and Asia.
OFS pricing. The majority (85%) of operators entered 2022 expecting services pricing to increase. A fundamentally strong global economy was driving higher pricing expectations for labor, tubulars and transportation. Oil service companies had only begun to implement pricing increases for select products and services in 2021, carving back substantial savings passed on to operators during the pandemic.
Higher pricing materialized in 2022 as expected, with 39% of operators experiencing broad service pricing increases. This slightly leads second-place pumping consumables at 33%, while completion and other downhole tools came in third place with 17%, and pressure pumping equipment was in fourth place, with 11% of companies experiencing the greatest pricing increases. Drilling-related rigs and consumables lagged more significant pricing increases in completions and production-oriented consumables, equipment and tools at the start of the year.
Drilled-but-uncompleted. U.S. operators made considerable progress working down the DUC backlog in 2021. However, the decline in gas prices has made many of these temporarily abandoned wells less attractive, as operators know the break-even price from completing other wells on the lease and are apparently waiting for higher commodity prices.
As of December 2022, the DUC total stood at 4,577, just 1% less than reported by the EIA a year earlier. In the Haynesville, the DUC count jumped 61% on a y-o-y basis and stood at 607 in December. Gains were also reported in the Niobrara (+50%), Appalachian (+28%) and Bakken (+16%) regions. The Permian basin continued on its downward trajectory, with 1,069 DUCs tallied in December, down 26% y-o-y, while the Eagle Ford registered a 30% decline, dropping to 508 DUCs in inventory in December.
U.S. RIG COUNT
Since hitting an all-time low of 244 rigs in August 2020, the U.S. rig count steadily improved in 2021 and 2022. At the start of 2022, the Baker Hughes Rig Count stood at 588 and rose throughout the year before reaching a climax of 784 the week of Nov. 23. It stood at that level the remainder of the year averaging 780 throughout December. As of Feb. 17, the rig count stood at 760, suggesting that the activity level will remain below 900 for the remainder of 2023 at current commodity prices.
U.S. WELLS FORECAST/NEWS
Given the aforementioned indicators, along with our surveys of operators and state agencies, World Oil predicts that U.S. drilling will increase 8.2%, to 20,655 wells in 2023. We also expect footage drilled to improve at a slightly higher pace, with about 289 million feet of hole expected, for an increase of approximately 8.7%, Table 1.
U.S. GULF OF MEXICO
In line with the global trend and hard push to convert to renewables fading, operators will again step-up work in the Gulf of Mexico, seeking greater returns over longer time, Fig. 3. They are also determined to reduce GHGs with offshore carbon capture and storage projects. Accordingly, we expect a 12.7% increase in wells drilled (142) and an 11.7% increase total footage during 2023.
Talos Energy reported two deepwater discoveries in the Gulf of Mexico during fourth-quarter 2022. One is at their Lime Rock prospect, and one is at the Venice project. Both operations encountered commercial quantities of hydrocarbons, with 78 ft of net pay at Lime Rock and 72 ft of net pay at Venice. Pressure, fluid and core samples from the wells confirmed the discoveries. Expected, combined, gross production rates should reach pre-drill estimates of approximately 15-20 Mboed. Estimated, combined, gross recoverable resources are forecast between 20-30 MMboed, with 40% oil and 60% liquids.
The two wells will produce through a shared riser system at the Ram Powell deepwater facility. Talos is also focusing on developing an aggressive CCS initiative in the GOM, using a significant amount of its free cash flow. The company expects CCS technology will take 6-15 years to develop, but to reach net-zero, CCS must be part of the solution. Arena Energy purchased seven blocks and 12 platforms in the shallow-water GOM from GOM Shelf LLC on Dec. 12. The acquisition includes net daily production of 2,000 boed in fields with historically low decline rates.
Federal GOM lease sales. The U.S. Inflation Reduction Act required the Bureau of Ocean Energy Management (BOEM) to accept the results of a recent federal oil and gas lease sale and to hold two additional lease sales. A plank in the IRA says that BOEM, in compliance with congressional direction, must accept 307 highest valid bids from Lease Sale 257 in the GOM, totaling $189.9 million.
BOEM originally held the lease sale in November 2021, but a federal judge invalidated the results in February 2022. The IRA invalidates the judge’s action and reinstates Lease Sale 257’s results. Furthermore, the IRA instructs BOEM to hold O&G Lease Sales 259 and 261. Congress directed that Lease Sale 259 be held by March 31, 2023, and Lease Sale 261 by Sept. 30, 2023.
In Texas, 11 of the 12 Railroad Commission Districts will be up this year, and shale drilling will continue to dominate the state. However, oil-producing regions will get more attention, with sustained crude prices expected to continue, due to restricted Russian supply. Therefore, we predict that statewide drilling will be up about 10.2% (9,976 wells), with total footage increasing 10.6%. The Permian will account for 50% of all drilling in the Lone Star state during 2023, Fig. 4.
Chevron will spend $4 billion in the Permian basin to accelerate low-risk U.S. shale output, which offers quick financial returns, compared with the multi-year megaprojects that dominated much of the last decade. According to Chevron, development in the basin assumes low double-digit cost inflation, while global expenses are likely to rise in the mid-single digit percentages.
Diamondback Energy agreed to buy drilling rights in the Permian basin for $1.5 billion in its latest expansion in the region. The company acquired drilling rights to 15,000 net acres in the Permian’s northern Midland basin area from Lario O&G for $850 million in cash and 4.18 million shares. A few weeks earlier, Diamondback purchased Permian explorer Firebird Energy for $1.5 billion.
Approximately 70% of the Permian’s premium acreage has been drilled, and producers are seeking more permits to drill beneath Midland and its 130,000 residents. Analysts say the Permian could reach a production plateau within five years. Producers in the Permian’s two main zones drilled in 2022 are yielding 8%-13% less oil per lateral foot than a year earlier.
Permian operators are also being forced to significantly increase flaring, due to a lack of pipeline capacity. Gas production has rebounded more quickly than crude in the basin since the end of the pandemic, which has maxed out pipeline capacity. However, several major pipelines are scheduled to come on-line in the second half of 2023, which will help reduce waste.
Marathon Oil completed its acquisition of Eagle Ford assets from Ensign Natural Resources for $3 billion. The assets produce mainly condensate and wet/dry gas. Marathon plans to deliver 67,000 net boed from 35 to 40 wells. The company will run one drilling rig in 2023 to maintain production levels.
Gulf Coast. In November, the Biden administration approved plans to build the nation’s largest oil export terminal in Freeport, Texas, which would add 2 MMbopd to U.S. oil export capacity. The approval by the U.S Department of Transportation’s Maritime Administration was filed in the federal register without public announcement. According to the U.S. Federal Maritime Administration, “The construction and operation of the port is in the national interest, because the project will benefit employment, economic growth and U.S. energy infrastructure resilience and security. The port will also provide a reliable source of crude oil to U.S. allies in the event of market disruption.”
The Southeastern region remains a mixed bag of plays. And this tends to produce a mixture of conflicting results. New drilling in the region is dominated by the Haynesville shale gas play in northern Louisiana. Drilling in that part of the state is forecast to be flat or slightly lower, due to the collapse of natural gas prices in the second half of 2022 and a lack of pipeline infrastructure. The combination of factors has contributed to a 61% y-o-y increase in the area’s DUC inventory. This, combined with abundant gas supply from other shale plays, will result in a modest 0.4% increase in Haynesville drilling activity in 2023. We predict drilling and footage totals to generally be the same as in 2022 (541 wells).
In southern Louisiana, activity in shallow oil fields by smaller companies will be essentially unchanged, despite higher crude prices. However, Mississippi will experience an 8.1% improvement in total wells and an 8.7% increase in footage. Alabama is the only state in the region forecast to suffer a decline in activity, with wells down 13.2% and footage off 12.2%.
The U.S. natural gas industry in the Northeast has plateaued, due to lack of pipeline infrastructure and the inability to build new ones, says EQT’s Toby Rice. A 2023 EIA report shows that the Marcellus/Utica continues to produce the same volume of natural gas as in 2022, essentially capped at 35.3 Bcfd. However, EIA predicts production will increase to 35.4 Bcfd in first-quarter 2023. These factors, combined with a 27.8% y-o-y increase in Appalachia’s DUC count, we predict that activity in gas-prone Pennsylvania and West Virginia will be essentially unchanged from last year, Fig. 5.
In Ohio, which produces more liquids than its neighbors, the number of new drilling permits issued to companies exploring the Utica/Point Pleasant shale formation in Columbiana County increased substantially in 2022, compared with the previous two years. The Ohio Department of Natural Resources reports that drillers secured 40 permits to drill new horizontal wells across the county as of Dec. 27, a 60% increase from the same period in 2021 and a 233% increase compared to 2020. According, World Oil forecasts an 8.9% jump in wells, accompanied by a 6.4% increase in footage.
This region has a long history of oil and gas production, but it has virtually no shale plays. As such, conventional vertical drilling to typical sand, limestone and CBM reservoirs remains dominant. Despite good gains in Michigan (+7.7%), Indiana (+6.3%) and Kentucky (+17.8%), the region will be pulled down by a decline in Illinois (-7.8%). Conventional oil drilling in Illinois, which will have the region’s highest volume of new drilling, is lagging but there will be a small return to CBM activity in the state.
In Michigan, a renewed push for exploration and higher oil prices will raise activity nearly 8%. Exploration wells will account for 29% of all drilling. Footage will be up 30%, as operators push deeper into the basin looking for new reserves at 70 locations. Indiana’s operators will increase activity modestly, with about 85% of wells targeting shallow, conventional oil. Footage will increase 8.3%. Kentucky officials expect an 18% jump in wells and a 2.5% increase in footage, with operators planning to boost oil development work.
The region will be one of the top performers in in 2023, with drilling in the region improving 12.0% (3,625 wells) and noticeable gains expected in all states. Activity continues to improve in Oklahoma's SCOOP and STACK plays, as operators have struck some big oil producers in the last year. Continental Resources completed a Carter County well flowing 1,099 bopd and 160 mcfg from the Sycamore formation at the Catskills 1-1-12xhm well in section 6-2S-3W, 4 mi southwest of Ratliff City. It was drilled to a TD of 17,740 ft. Drilling will be up 18% in the Sooner state and will be split 80% oil and 20% gas. Shale work will compose approximately 35% of total activity.
North Dakota is heading for an oil production bottleneck unless it either finds new markets for its natural gas or devises alternative transportation methods. More than half of the state’s annual income comes from tax revenue from oil. Despite the setbacks, we forecast drilling and footage to rise 4%, Fig. 6. In conventionally oriented Kansas, operators are pushing activity 12% higher by drilling relatively shallow wells at a ratio of 90% oil and 10% gas.
Drilling activity in Colorado has inched upwards over the last 12 months, but investor demands and supply constraints, not state or federal policy, will likely limit production growth in 2023, Fig. 7. Large producers operating in Colorado told investors they would use high oil prices to increase dividends and stock buybacks, not expand production. We expect well and footage totals to increase 6%.
In Wyoming, Canadian Overseas Petroleum confirmed its deep oil discovery in Converse and Natrona counties, Wyoming. A report by consultancy Ryder Scott indicates that the discovery contains 995 MMbbl of original oil in place. The company holds a significant acreage position in the region and plans to drill three additional horizontal wells in 2023 to further delineate the discovery. Overall, the state’s drilling and footage totals will gain around 11%.
In New Mexico, billions of dollars of new tax money are expected in the next fiscal year, driven by increased oil and gas production from the Permian basin in the southeastern corner of the state. The latest state report showed the potential for $3.6 billion in new revenue for 2024, representing 43% growth from the 2023 budget. Drilling should be up 6.4%, with a footage gain of 7%.
In California, operators have a difficult path forward, given the regulatory and political hurdles being put in front of them. Nevertheless, development continues in the greater Kern Country heavy oil area. Drilling will be off by around 3%.
In Alaska, BOEM held a 224-block OCS lease sale on Dec. 31 in the Cook Inlet’s northern portion, covering 1.09 million acres of seafloor. BOEM believes the leases could produce up to 200 MMbbl of oil and 300 Bcfg. Alaska’s Department of Natural Resources believes state oil output will remain around 500,000 bpd and then rise a bit after 2027. They cite a number of development projects scheduled, including the Santos FID to proceed with the Pikka project, slated to produce 80,000 bopd.
Drilling will be up 11% onshore, with total footage jumping 11.5%. Meanwhile, activity is healthy on Alaska’s North Slope, and drilling by several operators will be up 20%.
Editor’s note: We thank our friends at the various state agencies and many operators, who provided assistance with data that helped to shape this forecast.
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