Tag Archives: Pressure Pumping

Wells drilled but not completed rise again in November

The Energy Information Authority (EIA) released its latest Drilling Productivity Report that showed the number of wells drilled but not completed (DUC’s) rose for the 12th successive month.

At the end of November, the total for the 7 major onshore producing areas in the lower 48 states was 7,354, up 94 on the previous month. The total is 1,900 more than December 2016. DUC’s in the Permian Basin have now doubled since the end of last year (from 1,281 to 2,613).

Wells drilled dropped for the 3rd successive month, while completions rose slightly to 1,086, up 66% on completions in December 2016.

The DUC’s will remain high for some time due to a shortage of equipment and personnel. Evidence of this came last week when Keane Group announced they had placed orders for three additional frac fleets (50,000 hydraulic horsepower each) for a total cost of $115 million. Two of the units will be delivered by the end of the second quarter of 2018 and the third by the end of the third quarter.

Keane’s capital expenditure works out to about $770 per hydraulic horsepower. That shows that capital costs are rising rapidly for pressure pumping equipment and are approaching cost levels last seen in 2014. Mammoth Energy Services disclosed in its recent 10-Q that it expects to spend $64 million in 2017 to add 132,500 horsepower of new frac pumps and equipment. That works out at $483 per hydraulic horsepower. The company also stated that, historically, frac fleets cost $1,000 per hydraulic horsepower.

 

Weatherford-Schlumberger JV wins regulatory approval

Back in March Weatherford and Schlumberger announced a joint venture called OneStim that would combine their pressure pumping operations, multi-state completions and pump-down perforating businesses in the USA and western Canada. Weatherford would also contribute some manufacturing facilities and supply chain resources while Schlumberger would give the JV access to its surface and downhole technologies.

On Tuesday, the deal gained all regulatory approvals and is now expected to close before the year-end.

Weatherford 11-28-17 – OneStim JV receives regulatory clearance

Weatherford will own 30% of OneStim while Schlumberger  will own the rest. Schlumberger will also pay Weatherford a one time cash payment at closing of $535 million. That amount could change if the costs of re-activating the fleet are different from that envisioned when the deal was originally signed.

Weatherford actually shut down its US pressure pumping operations in November 2016. It is believed have about 20 frac fleets with about 800,000 to 1 million hydraulic horsepower (HHP). When the deal was announced, Capital One Securities analyst Luke Lemoine believed that, of the 20 fleets, “9 are ready to go back to work with zero capex, 1 fleet is hot-stacked, and the other 10 fleets would cost $5-$7 million to reactivate”. I believe that reactivation cost will be higher.

Schlumberger is believed to have 2 million HHP, so together the JV will be challenging market leader Halliburton which has just over 3 million HHP (about 20% of the total US capacity). BJ Services is third with around 2.2 million HHP.

When the OneStim JV was originally announced in March, analysts gave it a valuation of around $4 billion (Weatherford’s share would be $1.2 billion). That value has probably increased some since them given the quicker than anticipated increase in rig count and some analysts speculated that an IPO could occur in 2018. I also expect that Schlumberger will manage the assets better than Weatherford did which could substantially increase the value.

The $535 million proceeds will barely make a dent in Weatherford’s debt of $7.9 billion.¬†This Reuters report from last week stated that Weatherford was looking to sell its Artificial Lift and International Pressure Pumping businesses in Q1 2018.

Weatherford’s relatively new CEO, Mark McCollum (former CFO at Halliburton) certainly has his hands full.

 

 

 

 

 

Oilfield service trends from 3rd quarter earnings calls

Most of the oilfield service companies and many of the E&P companies have reported 3rd quarter earnings and I thought I would highlight some of the US industry trends highlighted in the calls.

The general theme was that land-based E&P operators had slowed down activity with the oilfield service providers in Q3. Even though a lot of drilling and completion equipment is fully utilized, price increases remain muted with the oilfield service providers preferring to see what customers do with their 2018 budgets before pushing additional pricing.

Halliburton

  • Pressure pumping equipment is sold out for Q4 2017. Halliburton are not planning to add new capacity to the market until pricing improves further.
  • Average amount of frac sand used per well remained flat in Q3. Note that in Q2 Halliburton said it had dropped for the first time in years which caused confusion in the market place as other companies weren’t seeing the same thing. In its Q3 call, Halliburton clarified that it was down in the Bakken, Rockies and the Northeast but up in the Permian.

National Oilwell Varco

  • Some customers who purchased purchase pressure pumping equipment were doing so before new tougher emission standards (Tier 4) come into effect at the beginning of 2018 for new product sales. (Note the standards were actually finalized in 2004, but transition arrangements were put into effect which are now being phased out at the end of 2017)

Keane Group (Pressure Pumping)

  • 25% of E&P companies are buying frac sand directly, rather than though a pressure pumping company, up from 10% at the start of the year. Gross margins for Keane are the same, whether they supply frac sand or not.
  • Gross profit per frac fleet was 19% in Q3. Gross profit percentage has to be in the ‘ low 20’s’ for new frac fleet builds to be economic.
  • Lead times for new frac equipment is 9 months
  • Pricing has stagnated as E&P companies pause some of their drilling activity and work on their 2018 budgets.

Hi-Crush Proppants (Frac sand provider)

  • I mentioned in a recent post that shortages of sand truck drivers caused some E&P operators to hold off some completions in Q3. Hi-Crush said that they didn’t have that problem, but suffered from a driver issue of a different kind. Earnings came in at the lower end of the range that analysts expected because Canadian National Railway canceled 20 unit trains (200,000 tons) because of a train driver shortage.
  • Average selling price of frac sand per ton was $68 in Q3, up $4 on Q2 (6.25%) and $25 on Q3 2016 (58%). They also stated that they raised prices significantly higher with a large customer, effective 1 Sept.
  • Hi-Crush brought on-line the first sand facility in the Permian basin.

Nabors Industries (Land drilling contractor)

  • Spot rates for higher end rigs are close to $23,000 a day (up from about $20,000 in Q2), though many of their rigs are working on existing contracts with an average rate of $19,000 (flat from Q2).

Transocean (Offshore drilling contractor)

  • Floating fixtures awarded in 2017 to-date have already exceeded last year’s total by approximately 40%. The deepwater drilling industry has now experienced six consecutive quarters with increasing floater contracting activity.

 

 

 

Oilfield service trends from last week’s earnings calls

 

Allan D. Hasty

The second quarter earnings season kicked off in earnest last week with most of the major oilfield service companies reporting as well as a few E&P companies (more report this week). I thought I would highlight some of the US industry trends mentioned in the calls.

 

Halliburton

  • In Q2 the average amount of frac sand used per well dropped for the first time in years. Customers are optimizing completion design using more science.
  • Pressure pumping capacity is sold out for Q3. The company doesn’t anticipate adding much new capacity in the near future.

National Oilwell Varco

  • After rising 15% off the bottom, day rates for land rigs in North America have stalled around $20,000 a day.
  • Recent reduction in the price of oil has caused many customers to delay large capital equipment orders.
  • Lead times for new pressure pumping equipment now close to 6 months.

Core Laboratories

  • Increased interest from E&P operators in enhanced oil recovery technology that could increase recoveries from an average of 9% in shale reservoirs to 13-15%.
  • E&P operators interested in using finer proppants in a hydraulic fracture program (i.e 100, 200 and 400 mesh sand).
  • Lateral lengths in horizontal drilling may have reached their maximum (10,000 feet) owing to frictional forces of pumping the frac fluid.

Basic Energy

  • Industry-wide – there is no available frac capacity and existing fleets are being worked harder so that the average life is down to 4 years.
  • Even if the rig count flattens, no impact on completion activity until mid 2018 given the backlog of DUC’s (wells drilled but not completed)
  • For Basic specifically pressure pumping prices were up 7-10% in Q2 over Q1

A number of E&P companies announced reductions in 2017 capex levels

  • Hess announced it would reduce its 2017 capex budget by $100 million to $2.15 billion, though it forecast that production for 2017 would increase slightly.
  • Anadarko is cutting its 2017 budget by $300 million to $4.2 billion – $4.4 billion, mostly in international exploration and deepwater drilling. It maintained its previous production guidance.
  • Whiting Petroleum (Denver-based, Bakken focused) is cutting its capex budget by $150 million to $950 million. It plans to drop two drilling rigs though it has a backlog of DUCs. It reduced its 2017 midpoint production guidance by 4%.
  • ConocoPhillips is cutting its capex budget by $200 million to $4.8 billion.
  • Sanchez Energy said it would go from 8 to 5 drilling rigs by the end of Q3, reduce capex in 2017 by an unquantified amount and reduce 2018 capex from $500 million to $400-$425 million. Its 2017 production forecast was reduced by about 10%. The company conducted a trial by completing 11 wells in the Eagle Ford field with 3,000 pounds of proppant per foot. They normally do 1,800 pounds. Results were disappointing and they have gone back to their standard usage of proppants.