Dallas Fed: Oil and gas activity edges lower as outlooks dim, uncertainty rises

MANAGEMENT ISSUES

MICHAEL PLANTE and KUNAL PATEL, Dallas Federal Reserve Bank  

Fig. 1. The business activity index decreased from 12.5 in the second quarter to -5.9 in the third quarter.

Activity in the oil and gas sector declined slightly in third-quarter 2024, according to oil and gas executives responding to the Dallas Fed Energy Survey. The business activity index, the survey’s broadest measure of the conditions that energy firms face in the Eleventh District, decreased from 12.5 in the second quarter to -5.9 in the third quarter, Fig. 1. The business activity index was 0 for exploration and production (E&P) firms, compared with -18.1 for services firms, suggesting activity was unchanged for E&P firms but declined for service firms.

OVERVIEW 

The Dallas Fed conducts the Dallas Fed Energy Survey quarterly to obtain a timely assessment of energy activity among oil and gas firms located or headquartered in the Eleventh District.  

Methodology. Firms are asked whether business activity, employment, capital expenditures, and other indicators increased, decreased or remained unchanged, compared with the prior quarter and with the same quarter a year ago. Survey responses are used to calculate an index for each indicator. Each index is calculated by subtracting the percentage of respondents reporting a decrease from the percentage reporting an increase.  

When the share of firms reporting an increase exceeds the share reporting a decrease, the index will be greater than zero, suggesting the indicator has increased over the previous quarter. If the share of firms reporting a decrease exceeds the share reporting an increase, the index will be below zero, suggesting the indicator has decreased over the previous quarter. 

Data were collected Sept. 11–19, and 136 energy firms responded. Of the respondents, 91 were exploration and production firms and 45 were oilfield services firms. 

Special questions this quarter focus on the effect of Waha Hub natural gas prices on activity; whether operators will ramp up completions, once the perceived natural gas pipeline bottleneck in the Permian basin is cleared; whether crude oil production in the Permian basin will be constrained between now and 2026 by pipeline constraints; plus several questions on oilfield electrification.  

OIL AND GAS PRICES/SUPPLY & DEMAND 

On average, respondents expect a West Texas Intermediate (WTI) oil price of $73/bbl at year-end 2024; responses ranged from $55.00/bbl to $100/bbl, Table 1. When asked about longer-term expectations, respondents, on average, expect a WTI oil price of $81/bbl two years from now and $87/bbl five years from now.

Survey participants expect a Henry Hub natural gas price of $2.62/MMbtu at year-end, Table 2. When asked about longer-term expectations, respondents, on average, anticipate a Henry Hub gas price of $3.24/MMBtu two years from now and $3.89/MMBtu five years from now. For reference, WTI spot prices averaged $70.82/bbl during the survey collection period, and Henry Hub spot prices averaged $2.23/MMBtu.

A special question asked executives at E&P firms, “In the Permian Basin, what impact have low Waha natural gas prices had on your operations in the third quarter of 2024? The Waha Hub is a gathering location for natural gas in the Permian Basin and connects to major pipelines. Of the executives surveyed, 52% selected “other;” the most-cited reason was little to no impact on operations, followed by reduced natural gas revenue, Fig. 2. Thirty-five percent said low Waha Hub natural gas prices caused their firm to curtail production. Twenty-six percent said low natural gas prices caused them to delay/defer well drilling, and 9% noted they delayed/deferred well completions. Respondents were able to select more than one choice for this special question. Among those who selected “other,” only one chose any of the remaining options. 

Fig. 2. Of the executives surveyed, 52% selected “other;” the most-cited reason was the Waha Hub had little to no impact on operations, followed by reduced natural gas revenue.

Another special question asked executives at oil and gas support services firms, “What impact did low Waha Hub natural gas prices have on demand for your firm’s services in the Permian in the third quarter of 2024? The majority of executives surveyed, 47%, said low Waha Hub natural gas prices slightly, negatively affected demand for their firm’s services in the Permian Basin in the third quarter, Fig. 3. Thirty-seven percent noted no impact, while 17% percent said the low Waha Hub prices had a significantly negative impact on demand for their firm’s services in the basin in the most recent quarter. 

Fig. 3. Eighty percent of executives said they are not planning to ramp up well completion activities in the Permian basin, once the natural gas pipeline bottleneck clears.

FINANCIAL OUTLOOK 

The company outlook index turned negative in the third quarter, plunging 22 points to -12.1, suggesting modest pessimism among firms. The overall outlook uncertainty index jumped 25 points to 48.6, suggesting mounting uncertainty. 

OIL AND GAS PRODUCTION 

Oil and gas production was mixed in the third quarter, according to executives at E&P firms. The oil production index increased from 1.1 in the second quarter to 7.9 in the third quarter, suggesting oil output increased slightly in the quarter. Meanwhile, the natural gas production index declined from 2.3 to -13.3, suggesting natural gas output decreased in the quarter. 

A special question to executives at E&P firms asked, “Is your firm planning to ramp up well completion activities in the Permian basin, once the natural gas pipeline bottleneck is cleared?” Eighty percent of executives said they are not planning to ramp up well completion activities in the Permian basin, once the natural gas pipeline bottleneck clears, Fig. 4. The remaining 20% said their firm plans to do so.

Fig. 4. Ninety-two percent of executives said they do not expect their firm’s crude oil production to be limited between now and the end of 2026, due to crude oil pipeline capacity constraints in the Permian.

An additional special question asked executives at E&P firms, “Do you expect your firm's crude oil production to be constrained at any point in time between now and the end of 2026, due to crude oil pipeline capacity constraints in the Permian?” Ninety-two percent of executives said they do not expect their firm’s crude oil production to be limited between now and the end of 2026, due to crude oil pipeline capacity constraints in the Permian, Fig. 5. The remaining 8% said that they expect constrained production. 

Fig. 5. Eighteen percent of executives said their firm’s oilfield operations are already fully electrified.

OFS SECTOR 

Costs rose but at a slower pace when compared with the prior quarter. Among oilfield services firms, the input cost index fell from 42.2 to 23.3. Among E&P firms, the finding and development costs index declined from 15.7 to 9.9. Meanwhile, the lease operating expenses index edged lower from 23.6 to 21.3. Two of the three cost indexes trailed the series average, suggesting costs are growing at a slower-than-average pace. 

The equipment utilization index for oilfield services firms turned negative, declining from 10.9 in the second quarter to -20.9 in the third. The operating margin index fell sharply from -13.0 to -32.6, suggesting margins declined at a faster pace. The prices received for services index was relatively unchanged at -2.3. 

EMPLOYMENT TRENDS 

The aggregate employment index was unchanged at 2.9 in the third quarter. While this is the 15th consecutive positive reading for the index, the low-single-digit result suggests little-to-no net hiring. The aggregate employee hours index declined from 8.1 to -2.3. Additionally, the aggregate wages and benefits index decreased from 24.0 to 18.6. 

OILFIELD ELECTRIFICATION 

Three special questions focused on matters related to oilfield electrification. The first of these asked all companies, “Is your firm aiming to electrify its oilfield operations?” Eighteen percent of executives said their firm’s oilfield operations are already fully electrified, Fig. 6. Six percent of executives said they aim to completely electrify oilfield operations for their firm, and an additional 31% said they expect to partially electrify operations. The remaining 45% said they do not plan to do so. 

Fig. 6. A majority of executives—54%—said the current lead time for electrical components, such as transformers, is not more than one year.

Responses differed, depending on the firm’s size and type. Twenty-eight percent of the executives surveyed from small E&P firms (crude oil production of fewer than 10,000 bpd, as of fourth quarter 2023) said their oilfield operations are already fully electrified, compared with 9% of executives from oil and gas support services firms and 6% of large E&P firms (production of 10,000 bpd or more). Service firms were also slightly more likely than small and large E&P firms to indicate that they are not aiming to electrify their oilfield operations.   

A second question asked respondents, “What is the current lead time for electrical components, such as transformers?” A majority of executives—54%—said the current lead time for electrical components, such as transformers, is not more than one year. Twenty-one percent of executives said the lead time is more than one year but not more than two years. An additional 10% of executives said more than two years but not more than three years. No executives said three years or more. Fifteen percent of executives noted there is no lead time for electrical components, such as transformers. 

The third and final question asked executives, “What is the top challenge to electrifying oilfield operations?” Firms aiming to electrify oilfield operations, or that have already done so, were asked whether their operations were primarily focused on the Permian basin or outside the Permian basin. Among firms primarily focused on the Permian basin, the top selected challenge was “uncertainty about future access to the grid” (29%), followed by “other” (25%). The most-cited reason for “other” was challenges with grid infrastructure. Among firms primarily focused outside the Permian, the top selected challenge was “too expensive” (30%), followed by “lead times for equipment” (26%). 

Among respondents not looking to electrify, the most-cited response was “too expensive” (48%), followed by both “uncertainty about future grid stability” and “other,” which were each selected by 17% of respondents. 

COMMENTS FROM SURVEY RESPONDENTS 

These comments are from respondents’ completed surveys and have been edited for publication. Comments from the Special Questions survey can be found below this set of comments. Editor’s note: These comments were provided in mid-September, well before the national election on Nov. 5. No doubt, some of the concerns expressed about regulatory policies have been allayed by the election results.  

EXPLORATION AND PRODUCTION (E&P) FIRMS 

• Recent volatility has started to impact planning discussions for 2025. We have not adjusted our plan yet, but we are starting to work on potential drilling plans for a lower commodity environment. 
• The political uncertainty is not helping the market. 
• The uncertainties due to legal assaults, cumbersome policies and invasive regulations create severe hurdles for small E&P operators. 
• There is greater uncertainty surrounding the economy and the oil market. Much of this has to do with the election uncertainty and the anticipated impact on the overall market. 
• Natural gas production in the Permian basin is priced well below the futures market. Several of the past months I have received nothing or a negative adjustment to revenue for natural gas. In June, one operator paid $0.09 per million cubic feet, which is above $0, but accrues little to my revenue. I believe this situation will persist for months if not years. 
• We are seeing natural gas prices affect drilling rig utilization in the East Texas Basin. The Eastern Haynesville drilling rig utilization is dropping off, and drilling rig utilization in the Western Haynesville/Bossier Sands play is increasing, due to higher production rates being found there. 
• Oil inventories are increasing, causing downward pressure on the per-barrel price of oil. Instability in Ukraine and the Middle East is a cause for concern for long-term oil and gas deliveries, which OPEC is less influential on. My opinion would suggest an increased oil price in 2025. 
• If we don't change from the current U.S. administration, oil prices and the oil industry will decline, and we'll become more dependent on foreign oil imports—hurting our economy and losing good-paying oil industry jobs. 
• Turbulent commodity pricing markets, specifically WTI (West Texas Intermediate) crude oil and Henry Hub natural gas, do not allow for confident future performance projections when it comes to net income. Merger and acquisition (M&A) markets are sluggish with a lack of quality assets and lower deal volume by deal count. Large corporate mergers are leading the M&A space, as assets are reshuffled and the larger companies try to create shareholder returns outside of the drill bit. We need a healthier M&A market to grow our company via acquisitions. 
• The recession scare is front and center. The presidential election is a side show in terms of actual effects for most energy firms. As the Fed [Federal Reserve] cuts rates, the economy is either headed for a recession, which is bad news for oil, or somehow, we will manage the first soft landing in the history of the nation. For oil and gas companies, they will, unfortunately, be punished until the soft landing outlook is actually in the rearview mirror. No one wants to invest in oil and gas. Sentiment has thawed very slightly from zero investors interested to one or two on the margin. It is just brutal out there. 
• Our company outlook could increase, if the executive leadership shifts to conservative. 
• The lack of investor interest in oil and gas exploration is an issue affecting our company. Another issue is a decrease in oil and gas revenues, due to depletion and lower prices. 
• Oilfield operating cost inflation is a major concern in the industry. 
• Regulatory uncertainty and changes are affecting our company. 
• The administration’s “death by a thousand cuts” keeps impacting my company in different quadrants. All are aimed at increasing the cost of doing business in oil and gas and aimed at keeping oil and gas independents from staying in business. 

Oil and Gas Support Services Firms 

• The consolidation and shutting down of oilfield service firms will hurt the ability of the U.S. to ramp up in the face of international supply disruptions. 
• Lead times for electrical components (transformers, capacitor banks, reclosers) have increased from 10–12 weeks to 100–120 weeks, and costs are up 50–80%. There’s no way the projected increased demand for electricity (driven by data centers and/or artificial intelligence) will be achievable in the time frame projected. 
• I think [there will be] no change until the election. Oil is down an alarming amount, but my clients have me busy. 
• The current disconnect between oil price and physical supply is worrisome. Prices are not supportive of the long-term investments needed to maintain adequate supplies through the energy transition. As a result, the current underinvestment will lead to significant inventory shortfalls in the medium term, followed by rapid price escalation. It's going to be a very bumpy ride ... again. 
• We are hearing and seeing a continued reining in of activity from our customers, due to the uncertainty regarding the November elections. There is work out there, but it is just being held until there is some certainty regarding energy policy. 
• Middle Eastern politics seem to play less and less of a factor in determining the price of oil, and the price more and more reflects worldwide economics. 
• Consolidation of operators in the upstream sector continues to ripple through the service sector. Less continuity of work makes it hard to maintain skilled labor. 
• Activity levels are up slightly, but the market still feels cautious. Whether the caution is driven by the continuous M&A or the election is unclear to us. As a smaller service company, the scale of the larger operators is making it more difficult to access goods for smaller operators than we have seen in the past. 

SPECIAL QUESTIONS COMMENTS 

EXPLORATION AND PRODUCTION (E&P) FIRMS 

• We stand by the hypothesis that the world is swiftly running out of $60 barrels on the way to $100+ barrels within the next five years. OPEC is being punished, short term, for ceding market share. To us, it appears to be a savvy "oil storage" policy. U.S. shale will decline in a similar fashion to how Hemingway went bankrupt: "Gradually, then all of a sudden." Why do you think very sophisticated firms, worth tens of billions of dollars, are selling out to the super majors for equity despite a market-leading Permian footprint? 
• The oil community prefers to await the allocation of capital until after the election. Deflationary pressures in China continue to curtail oil demand. India is buying cheap Russian oil, which is also helping cap world prices. Future OPEC+ production allotments are uncertain. The lack of a war-price premium in product prices is a concern. Technical analysis of the recent oil-price movements suggests that WTI could drop to around $55 per barrel, depending on whether the U.S. is entering a recession. 

OIL AND GAS SUPPORT SERVICES FIRMS 

• Most of our rigs are capable of running off grid power, but the logistical (regulatory and permitting) hurdles that our customers have to go through to bring power to the rig are formidable and expensive. 
• The Electric Reliability Council of Texas and/or Public Utility Commission of Texas is struggling with regulatory framework around distributed generation, behind-the-meter generation and grid interconnections. Statutory requirements for utilities to approve grid interconnections have no teeth; what should take three months now takes 12 to 18 months. Lead times for intermediate voltage (~14KVa) transformers, etc., are now two to three years, and utility-scale high-voltage components are in the five-to-seven-year range. Utility-scale battery backup costs roughly 10 to 15 times the cost of natural gas-powered peaking facilities. Concerns about being able to meet projected demand driven by AI and/or data centers and/or bitcoin mining abound. Serious concerns about large tech players locking up baseload and peaking power supplies and driving up the costs for consumers also exist. 
• I am not convinced that electric-powered vehicles and equipment can hold up to the operational demands placed on them in our industry. That and the cost of parts (especially batteries) cause many concerns. The continued rhetoric (mostly political) about doing away with the fossil fuel industry continues to be a sore spot with our company, our employees and our customers. The contributions made by the oil and gas industry have been the backbone of our economy for a very, very long time. All "they" want to focus on is some of the pitfalls of oil and gas exploration and production without looking at the great strides our industry has made in terms of efficiency, cost reduction and especially safety. Maybe "they" need to learn how much fossil-fuel products impact their everyday life. 
• To add the additional costs to electrify equipment, the returns have to be there through higher prices or reduced costs. That is not the case in our segment. 
• Our operations are far too mobile and fast-paced to install the necessary electrical infrastructure for operations. Additionally, suppliers are currently not making electrical options for many of our types of machinery. 

MICHAEL PLANTE joined the Federal Reserve Bank of Dallas in July 2010 and is senior research economist and advisor. Recent research has focused on such topics as the economic impact of the U.S. shale oil boom, structural changes in oil price differentials, and macroeconomic uncertainty. He also has been the project manager of the Dallas Fed Energy Survey since its inception in 2016. Mr. Plante received his PhD in economics from Indiana University in August 2009. 

KUNAL PATEL is a senior business economist at the Federal Reserve Bank of Dallas. He analyzes and investigates developments and topics in the oil and gas sector. Mr. Patel is also heavily involved with production of the Dallas Fed Energy Survey. Before joining the Dallas Fed in 2017, he worked in a variety of energy-related positions at Luminant, McKinsey and Co., and Bank of America Merrill Lynch. Mr. Patel received a BBA degree from the Business Honors Program at the University of Texas at Austin and an MBA degree in finance from the University of Texas at Dallas.