U.S. operators are teed up for a drilling resurgence
The U.S. E&P industry has survived an agonizing downturn, and now it seems poised to make a comeback. A rapid run-up of drilling activity in some parts of the U.S. suggests that companies have found ways to operate new wells profitably with oil prices that have, so far, been sustainably higher than what the industry experienced in 2016, Fig. 1. OPEC’s move to muster an oil output cutback—among its member countries and other large producers—also has played a part, propping up oil prices high enough for shale operators to rally.
One obvious indicator of American activity this year is the Baker Hughes U.S. rotary rig count, which stood at 958 active units on July 28. The current total is more than double what was counted a year ago, representing an increase of 495 working rigs. In fact, in each month since January, the monthly average has increased by a range of 40 to 61 rigs, according to Baker Hughes. Aside from that, U.S. capital expenditures are forecast to increase $26.2 billion, year-over-year, during 2017. Furthermore, World Oil’s mid-year survey respondents have indicated that they will increase their wells drilled by 19% in the back half of the year.
With these statistics in mind, World Oil is forecasting an impressive drilling increase this year, projecting 22,964 total wells for 2017—a 51.5% gain from the 2016 well count of 15,154, Table 1. Total footage is projected to climb from 159.2 MMft in 2016 to 249.6 MMft in 2017—a 56.8% boost. Within 2017, 10,954 wells are estimated to have been drilled during the first six months, while 12,010 are expected to spud in the last six months. An 11.1% increase in footage is expected during the second half of 2017, as well.
In one respect, the gain in drilling activity is a sign of the U.S. E&P sector’s fortitude. Companies are being fiscally prudent by transforming their businesses to operate more efficiently, while seeking to drill only in the core areas of each play—acreage with the best “break-even” economics. However, in another respect, it could give one pause, since the U.S. shale producers are thought of by many analysts as the culprits of the global supply glut. As the global oil and gas industry continues its crawl out from what is certainly the worst downturn since the 1980s (if not worse), there seems to be an abiding danger that the U.S. could cause a seesaw event. As such, it is with cautious enthusiasm that World Oil presents its 2017 midyear forecast for the U.S.
North American capex recovery gains speed. The price and activity downturn that crashed the E&P industry in late 2014 is finally receding. After possibly suffering the deepest capex cuts throughout the globe from 2014 to 2016—a 68% decrease—North America is on the move again. By year-end, NAM spending is expected to increase 41%, from $71.1 billion in 2016 to $100.3 billion in 2017, according to the 2017 E&P Spending Mid-Year Outlook from Evercore ISI. The report, authored by James West—senior managing director at the investment bank—is gathered from a twice-yearly survey and was released on June 19.
West and Evercore forecast that U.S. operators will lead the capex recovery, with a 44% increase over last year, from $58.8 billion in 2016 to $85 billion in 2017. For Canada, E&P spending is projected to rise 26%, from $12.3 billion in 2016 to $15.5 billion in 2017. Overall, Evercore has revised its 2017 capex forecast for North America, initially released in December, upward by 20%. “We were anticipating significant capex revisions to unfold in 2017 following the publication of our initial survey, especially considering that data was collected prior to the OPEC agreement in late November,” the report says. “The near-term beneficiaries of the upward revision to 2017 capex are clearly the companies levered to unconventional production in North America.”
While independents traditionally have driven shale activity, majors and other large operators are also starting to play a greater role in the unconventional sector’s rising popularity—refocusing capital from more expensive offshore plays to onshore shale wells. In fact, the report’s data show that five large firms—BP, Chevron, ConocoPhillips and Royal Dutch/Shell—plan to reduce international spending while boosting North American investment during 2017.
The firm’s survey also indicates 100% agreement among respondents that a WTI price of less than $45/bbl would be necessary for operators to cut capex. If a WTI price of $65/bbl or better materialized, 47% of North American operators said they would increase investments, and 37% said growth was possible if prices ranged between $60/bbl and $65/bbl. A whopping 73% of North American operators would increase capex, if the Henry Hub natural gas spot price surpassed $4.00/MMBtu.
Looking ahead to 2018, 65% of the survey’s total respondents—not just those in North America—expect to increase spending, compared to 2017 budgets. And 40% said that they expect budgets to increase more than 25%, compared to 2017.
Oil prices stifled by supply. In hopes of nurturing long-term price stability, OPEC has led a campaign to expand production cuts among its members, as well as other major oil producers. However, as more countries join the oil cartel’s cause, even extending the composite 1.8-MMbopd reduction through first-quarter 2018, there are U.S. shale producers lying in wait, ready to unleash a deluge of resources onto the market. Indeed, total U.S. oil production is forecast to average 9.3 MMbopd in 2017, up 0.5 MMbopd from 2016, when the initial agreement was made between OPEC members and 11 non-OPEC countries, according to the U.S. Energy Information Administration (EIA).
Before the agreement was made official, the ever-present supply glut had sunk WTI and Brent prices to the tepid levels of $43/bbl and $44/bbl, respectively, during fourth-quarter 2016. As prices then rose, optimism lingered through the first quarter of this year, as WTI ranged between $49/bbl and $54/bbl from December 2016 to March 2017, while Brent varied from $53/bbl to $57/bbl during the same period. Yet, word of surging shale activity muted buzz that the oil market was rebalancing, sending WTI as low as $47/bbl, and Brent to $51/bbl in March.
After that, oil prices have oscillated between aggressive advances—as OPEC fights to strengthen price-levels—and defeating retreats, as shale operators incrementally load the market with supply, stopping crude price growth. Finally, at the end of July, prices recovered from a May–June slippage into the low $40s/bbl, back up to the high $40s/bbl and low $50s/bbl.
Recovery in oil production from Libya and Nigeria also has limited crude momentum, stated the EIA’s Short-Term Energy Outlook published July 11. “The return of 0.1 MMbpd of combined crude oil production in Libya and Nigeria contributed to lower oil prices in June, as did builds in total U.S. crude oil and petroleum products inventories that were above the five-year average during the weeks ending June 2 and June 9,” said EIA authors.
The EIA forecasts WTI and Brent prices to average $48/bbl, and $50/bbl, respectively, during the second half of 2017, and the first half of 2018. WTI is forecast to increase from an annual average of $49/bbl in 2017 to an average $50/bbl in in 2018. Brent’s annual average is projected to increase from $51/bbl in 2017 to $52/bbl in 2018.
U.S. crude oil production unleashed. American tight oil production is expected to help the U.S. break an annual crude oil output record during 2018. EIA projects that the U.S. will build on the 9.3-MMbopd forecast for 2017 by an additional 300,000 bopd, producing an average 9.9 MMbopd next year. Such output would push past the last record of 9.6 MMbopd, achieved in 1970. By December 2018, EIA expects the U.S. to produce 10.1 MMbopd, which would be an estimated 1.4-MMbopd boost from the 2016 average. For reference, the U.S. produced about 9.7 MMbopd in June 2017.
Tight oil is expected to bring in the biggest U.S. growth, contributing 1.1 MMbopd of the total 1.4-MMbopd growth from 2016 to 2018, according to EIA. The cream of the crop is the Permian basin, stretching over 53 million acres in West Texas and southeastern New Mexico. Operators are forecast to produce 2.9 MMbopd by year-end 2018 in the Permian, a 0.5-MMbopd increase from June 2017. “With the large geographic area of the Permian region and stacked plays, operators can continue to drill through several tight oil layers and increase production, even with sustained WTI prices below $50/bbl,” said EIA, citing the Wolfcamp, Spraberry and Bonespring, in particular.
The Eagle Ford (Texas) and Bakken (North Dakota) shales are also expected to remain stable. Eagle Ford production is forecast to average 1.3 MMbopd in 2017 as well as in 2018, which would be a 100,000-bopd increase from late 2016, according to EIA. “Similar to the Permian, Eagle Ford wells have high initial production rates and fast decline rates, requiring the continuous drilling of new wells to maintain production levels,” said EIA. The Bakken is forecast to maintain flat production from 2017 to 2018, at 1.1 MMbopd.
The Gulf of Mexico also should contribute to U.S. growth, chipping in approximately 300,000 bopd in added output. EIA said that the GOM will average 1.7 MMbopd in 2017, and 1.9 MMbopd in 2018—a 0.3-MMbopd increase from the end of 2016. The agency cited the anticipated expansion of Tahiti field, and the start-up of Horn Mountain Deep field in 2017, along with the Big Foot and Stampede projects in 2018, as contributing to increases in GOM production.
Natural gas prices to see upward pressure. Winter warmed up earlier than normal during first-quarter 2017, which has limited gas demand and caused Henry Hub spot prices to stay flat for most of the year. The average price was $3.04/MMBtu for first-half 2017—the same as it was during fourth-quarter 2016. EIA forecasts the Henry Hub spot price to average $3.10/MMBtu for 2017, citing growing U.S. natural gas exports and an assumption of cooler temperatures this winter. EIA expects prices will average $3.40/MMBtu during 2018.
“Based on forecasts by the National Oceanic and Atmospheric Administration (NOAA), EIA projects 2017 heating degree days (HDD) to be similar to 2016 levels. The first quarters of both years were warmer than normal,” said the agency. EIA expects combined residential and commercial natural gas consumption to be almost unchanged in 2017, compared with 2016 levels, and then to rise by 1.2 Bcfd in 2018.
Natural gas exports ramp up with growing production. Just as unconventional shale plays have brought a renaissance to U.S. oil production, so too have they given new life to natural gas output. During 2017, U.S. dry gas production is forecast to average 73.3 Bcfd—1.0 Bcfd more than in 2016—and in 2018, dry gas output may reach an average 76.4 Bcfd. Such growth also has allowed the burgeoning U.S. LNG industry to establish itself, as average gross LNG exports are forecast to increase from 0.5 Bcfd in 2016 to 1.9 Bcfd in 2017, according to EIA. In 2018, average gross LNG exports are expected to reach 2.8 Bcfd.
U.S. rig count takes off. The industry continues to build on new techniques—such as pad drilling with walking rigs—that have made drilling wells more cost-effective, and thus have allowed companies to economically hire more rigs at one time. Certainly, lingering, low service costs, as a result of the most recent downturn, also play a part in operators’ favorable drilling economics. As a result, the Baker Hughes U.S. rotary rig count’s weekly figure has grown by 300 active units since the end of 2016, with the most recent count on July 28 coming in at 958.
Evercore and West forecast that the U.S. rig count will keep pushing higher this year, and through to 2018, due mainly due to increases in onshore activity. The firm projects an addition of 390 rigs by year-end 2017, and a 20% increase in 2018, relative to 2017, citing “public production targets by NAM independents” that necessitate such an increase.
The Permian, unsurprisingly, seems to be driving activity growth. In the past seven months, the rotary rig count in the Permian has jumped by 115 working units. “The Permian ramp up is here, and it’s big, driven by stronger E&P cash flows and savory break-evens,” said Evercore. “The stage is set for the Permian to be the first bastion of the upcycle, with E&Ps prepping work programs and service providers ready to capitalize, following two-years of unilateral E&P pricing oppression.”
World Oil’s operator surveys reflect optimism. To survive long term in the E&P industry—as an operator, oilfield services company, drilling contractor or OEM—it takes thick skin. In the midst of ever-changing oil prices that constantly shift the paradigm for profitability; uncertain regulatory environments; and murmurs of peak oil demand among even the largest oil companies, one might say that a “glass-half-full” perspective is a mandatory prerequisite. Put another way, one has to be an optimist. And if there’s one word that best describes the results of World Oil’s 2017 mid-year operator survey, it’s optimism, Table 2. Overall, the survey represents 21.5% of U.S. drilling.
World Oil’s survey reflects an 18.9% increase to 2,680 wells planned for second-half 2017, versus the 2,253 wells that were drilled by respondents in the first half. The results for total footage in the second half show a 21.4% trend upward. Major drillers will drive much of the growth, as these larger companies have indicated that they will boost drilling operations 23.8%, from 1,565 wells in the first half to 1,938 wells in the second half. The smaller independents’ responses reflect more stability between the first and second halves of 2017, returning a 7.8% increase, from 688 wells drilled in the first six months to 742 wells in the back half.
However, one piece of context that shouldn’t be ignored is that many companies are not planning to drill any wells at all this year, either in the first half or the second half. For instance, in California, 11 of the 19 total companies surveyed are completely inactive, and a similar trend is evident in many other states. Thus, the bold buildup of new wells reflected in World Oil’s survey only applies to companies with active drilling operations, principally larger independents in the best of the shale plays.
U.S. Gulf of Mexico remains stable. In terms of growth, the U.S. offshore industry’s recovery still lags behind the short-cycle onshore shale projects, Fig. 2. And according to World Oil’s survey results, and federal officials’ outlook, the sector remains sluggish through 2017. Accordingly, World Oil forecasts that GOM activity totaled 53 wells in the first half of the year, with another 57 to be drilled in the second half. This 110-well total for the year will be 22.5% lower than the 2016 figure of 142.
Interestingly, the seven GOM respondents to our survey run counter to this trend, indicating that they drilled 23 wells in first-half 2017, and that they plan to drill 26 wells in the second half, for a 13.0% increase. Together, the group represents 44.5% of the activity that we expect, but they also may be among the healthier operators in the GOM. Indeed, most of their activity remains deepwater-driven. Because these projects require long-term planning, they aren’t as exposed to the reactionary whims of oil price trends.
The Permian drives growth in Texas. The push that operators started recently—to drill up the most lucrative acreage available in the Permian basin—is still propelling gains in Texas. World Oil’s survey results indicate that operator plans will generate large gains in the state, leading to a forecast of 5,182 wells for the first half of 2017, and 5,400 in the second half. Together, the two halves will total 10,582 wells, for a magnificent 69.5% gain over 2016’s activity.
As one would expect, survey data from various respondents indicates that a large portion of Texas’ activity is occurring in District 8, the center of the Permian, Fig. 3. Drilling there will jump 5.2% higher during the second half, and activity for the full year will be an incredible 86.8% higher than the 2016 figure, at 4,058 wells. Also partially in the Permian, Districts 7C and 8A are expecting to ramp up. For District 7C, second-half drilling will be up 6.4%, and the overall 2017 figure of 974 wells will be 74.6% higher than in 2016. In District 8A, while drilling will be up only moderately in the second half, the year-to-year difference is still a dizzying 74.5%, with 951 total wells forecast. Illustrating the mood of many Texas operators, leadership at Occidental Petroleum and Pioneer Natural Resources recently expressed opinions that Permian projects can be economical at oil prices that are even lower than current levels.
Elsewhere in Texas, the Eagle Ford shale remains viable, although not quite as prolific as the Permian. For instance, District 1 will see drilling grow 3.8% in the second half, but the 2017 total of 1,247 wells will be up a very solid 35.5% from 2016’s level. In regards to District 2, we expect operators to drill 5.3% more wells in the second-half of 2017. If that happens, then the yearly total of 1,043 wells will be 59.5% above 2016’s figure. For more insight into these districts, please see Contributing Editor Jim Redden’s report on the Eagle Ford shale, on page 56 of this issue.
Oklahoma’s SCOOP and STACK plays maintain prominence. Operators in Oklahoma seem to be setting new records constantly for well production in the SCOOP and STACK plays. In the past six months, both Devon Energy and Continental Resources broke industry well records in the STACK. On July 11, Devon announced that it had brought a well online with a peak 24-hr rate of 6,000 boed in the core of the STACK’s over-pressured oil window. It was drilled with a 10,000-ft lateral.
On May 17, Continental Resources said that one of its STACK wells had flowed at an initial 24-hr test rate of 3,339 boed, including 2,345 bopd (70% of production), and 6.0 MMcfg. It is producing from the Meramec reservoir through a 9,700-ft lateral at a flowing casing pressure of approximately 2,400 psi, on a 34/64-in. choke. No doubt, such record wells are luring growth to Oklahoma. Thus, World Oil forecasts an 7.7% increase during the second half of 2017, to 1,159 wells. On an annual basis, the 2,235-well total will be up a resounding 70.7% from 2016’s level.
North Dakota’s Bakken still critical. Though analysts seem riveted on activity further south, in Texas, there is still significant drilling in the state’s Bakken shale. World Oil’s survey results from five operators suggest that they collectively will increase their work 34% during second-half 2017. When compared to state agency data, plans for the second half look even more bullish. As such, World Oil forecasts a 32.1% increase in the second half of the year, compared to 405 wells drilled in the first half. One possible factor limiting the increase in wells from being even sharper is a backlog of drilled but uncompleted wells (DUC) that operators must work through. For the year, North Dakota’s drilling will be up 18.8%, compared to 2016’s level.
Pennsylvania pushes ahead. Pennsylvania’s Marcellus shale play might have slipped to a low point of 600 wells in 2016, but that’s going to drastically change this year. The area is benefitting from the buildup of the U.S. natural gas sector, including LNG exports. According to operator survey results, 98% of the respondents’ wells drilled in 2017 will be gas wells. World Oil forecasts a 34% gain in second-half 2017 activity, compared to the first half. For the year, drilling will be up 77.8% from 2016’s level.
Rocky Mountain region builds back. World Oil also forecasts a healthy increase for the Rocky Mountain states, including Utah, Wyoming, Montana, which are expected to garner a 35.5% increase in the second half of the year—a 161-well addition. By contrast, in World Oil’s 2016 mid-year forecast, these states were forecast to experience an 80% drop from the first half of the year to the second half. Colorado and New Mexico are as solid as ever, and are forecast to increase their number of wells drilled by 9.2% from the first half of 2017 to the second half. Colorado should see 1,072 wells drilled this year, up 19.0% from 901 during 2016. New Mexico is forecast to drill 955 wells, up a whopping 64.9% from 579 wells in 2016. Much of New Mexico’s activity is focused in the southeastern part of the state, which contains part of the rich Permian basin.
California shows steady increase. The state of California drilled only 775 wells last year, most of them for heavy oil. However, according to operator surveys, the pool of 11 active operator respondents—only a small segment of the operators in the state—have already drilled 427 wells in first-half 2017, and are planning to drill 465 more in the second half. Thus, when extrapolated with the state agency data from California, World Oil predicts that a total of 505 wells will be drilled in the first half of 2017, and that 534 wells will be drilled in the second half—a total of 1,039 wells for the year.
Once again, World Oil would like to thank the many state agencies and operators who supplied data to us, and without whom this forecast would be nearly impossible to assemble. 
- Coiled tubing drilling’s role in the energy transition (March 2024)
- Advancing offshore decarbonization through electrification of FPSOs (March 2024)
- Shale technology: Bayesian variable pressure decline-curve analysis for shale gas wells (March 2024)
- Subsea technology- Corrosion monitoring: From failure to success (February 2024)
- Digital tool kit enhances real-time decision-making to improve drilling efficiency and performance (February 2024)
- E&P outside the U.S. maintains a disciplined pace (February 2024)
- Applying ultra-deep LWD resistivity technology successfully in a SAGD operation (May 2019)
- Adoption of wireless intelligent completions advances (May 2019)
- Majors double down as takeaway crunch eases (April 2019)
- What’s new in well logging and formation evaluation (April 2019)
- Qualification of a 20,000-psi subsea BOP: A collaborative approach (February 2019)
- ConocoPhillips’ Greg Leveille sees rapid trajectory of technical advancement continuing (February 2019)
