Winter Weather, Falling Demand Wallop Greater Rockies Pressure Pumpers

Synopsis

The combination of low commodity prices and seasonal weather has impacted demand for pressure pumping services in the greater Rockies (the Rocky Mountain markets outside the Bakken Shale).

However, a majority of participants in the Hart Energy interviews expect demand to fall until commodity prices recover, regardless of weather. The drop in demand has exacerbated a well stimulation market that was already oversupplied with equipment.

Currently, service providers estimate regional pressure pumping capacity at 500,000 in hydraulic horsepower (HHP), down from 800,000 HHP during the last survey in July 2015.

Service providers estimate there are 20 fleets at work in the region, though crews remain underutilized. Lateral lengths average 5,071 feet with 31 stages in the Niobrara, though stage count ranges from 25 to 35. Service companies are working at cash cost and scrambling to hold on until commodity prices recover.

Well stimulation providers say the average per stage price is $34,000 currently (ranging from $30,000 to $40,000), down 10% from $38,000 in July. Rocky Mountain service providers insist pricing will not fall any further since companies are at cash cost.

Although drilling has dropped significantly, the backlog of drilled but uncompleted wells continues to rise on the basis of a very slow pace in completions.

Watch for the next greater Rocky Mountain well stimulation update in July 2016.

Part I. – Survey Findings

Among Survey Participants:

• Demand Shrinking Quarter-To-Quarter in the Region
  [See Question 1a and 1b on Statistical Review]
  ​Five of eight respondents reported that fourth-quarter 2015 demand shrunk quarter-to-quarter because of the low oil price and a normal winter slowdown. Most respondents expect demand to shrink until price of oil recovers hopefully in 2016.
  • Mid-Tier Service Provider: “Companies were slowing down drastically already and now bad winter months make it even worse.”

• HHP Supply Excessive
  [See Question 2 on Statistical Review]
  ​All respondents reported an excessive supply of HHP capacity even as several frack providers reduced fleets in the region or shut fleets down entirely.
  • Mid-Tier Service Provider: “There are too many fleets still for the small amount of work as things continue to slow down here.”

• Fracking Capacity Reported Averages 500,000 HHP
  [See Question 3a, 3b, and 3c on Statistical Review]
  ​Among respondents, HHP capacity in the region is estimated to be approximately 500,000 HHP in the play, down from 800,000 HHP estimated in July. While most respondents did not make an estimate, a few estimated 20 fleets continue to serve the entire Rockies, though most are underutilized.
  • Mid-Tier Service Provider: “We are down to two dedicated fleets here now. We sent everything else to Texas.”

• Well Metrics: Vertical Depth Ranges ~6,900 Feet
  [See Question 4 on Statistical Review]
  ​Average vertical depth reported is 6,892 feet across the play. While a few respondents reported on Niobrara, most were reporting Uintah Basin and other areas. Average lateral length is 5,071 feet. Average number of stages is 31. Injection rates average 66 barrels per minute with about six stages completed daily on a 24-hour schedule.
  • Mid-Tier Operator: “We are usually doing 25 to 35 stage fracks in the Niobrara on 5,000-foot laterals.”

• Region’s Average Cost Per Stage Is ~$34,000
  [See Question 5a and 5b on the Statistical Review]
  ​The average per stage price is reported at $34,000, down from $38,000 estimated in July. All respondents expect prices to remain the same over the next three months.
  • Mid-Tier Service Provider: “Prices are at rock bottom. Mostly we are trying to hold at cost until recovery.”

• Backlog Of Fracks Continue In Rockies
  [See Question 6b on the Statistical Review]
  ​Most operators have slowed both drilling and completions of wells. A backlog of uncompleted wells continues to build until oil prices rise to justify fracking costs.
  • Mid-Tier Operator: “We see far fewer wells drilled now.”

End Survey Findings

Survey Demographics

H A R T E N E R G Y researchers completed interviews with eight industry participants in the well stimulation/pressure pumping service segment in the Rocky Mountain areas outside of the Bakken area. Participants included seven managers or sales personnel with well service companies, and one technical consultant working for an E&P company. Interviews were conducted during the first week of January 2016.

Part II. – Statistical Review

Well Stimulation/Pressure Pumping

[Rocky Mountains outside of Bakken]

Total Respondents = 8

[Fracking service providers = 7, Operators = 1]

1. Do you expect demand for pressure pumping equipment to grow, remain the same or shrink in fourth-quarter 2015 compared to the third quarter?

2. Would you characterize the supply of pressure pumping equipment in your area as excessive, sufficient or insufficient to meet late 2015 demand?

3a. How would you estimate total HHP capacity for the region?

3b. How many total crews (spreads) do you think are active in the area?

3c. Have any service providers left the play in the last 90 days?

4. What is the average vertical drilling depth, average horizontal lateral length, number of frack stages and injection rates (barrels per minute) in this play? What are the average frack stages per day? Is this a 12-hour or 24-hour shift?

5a. What is the average cost per stage in your area now?

5b. Do you expect fracking prices to increase, remain the same, or decrease over the next three months?

6a. What strategies are companies putting into place to cope with a low price environment?

6b. What are you seeing in terms of the number of wells drilled but not completed in your area?

End Statistical Survey