The End is the Beginning for Baker Hughes

The-End-Is-the-Beginning-Baker-Hughes-Primary-Vision-Blog-7-29-2016by Matt Johnson

Over the last week or so we’ve covered the Q2 results for Halliburton (HAL: $42.77), Schlumberger (SLB: $79.05) focusing on the good, the bad, the ugly and accompanying activity measurements. Today we will center in on Baker Hughes (BHI: $46.05) which reported its Q2 results on July 28th, 2016.

Just a reminder that, Primary Vision focuses on frac data and therefore will highlight (and probably lowlight) BHIs pressure pumping activity.

The Good: As a result of the $3.5b breakup fee paid by HAL, BHI has already earmarked a 1.5b share buyback program and $1b in debt repayments. Due to recent job cuts and other internal restructuring they’re expecting their margins to improve throughout the rest of 2016.

Water Volume – BHI was #3 in water usage in 2013 and 2014.  They slipped to #4 in 2015 and round out 5th place, so far, in 2016. Just an fyi: The running order of water usage from 2013 to current (from 1st to 5th place): HAL, SLB, FTS International, Pioneer Natural Resources (PXD: $157.54) & BHI (this water usage list only has Pressure pumpers, and while PXD is known as an operator they’re also vertically integrated with their own frac spreads which enables them to control costs on a whole other level.  Read here to learn more).

Proppant Volume – BHI had the 2nd highest proppant mass from 2013 to 2015.  2016 numbers are still a bit murky.

Total Number of Frac Jobs: In 2015, BHI held second place with 1,643 frac jobs.  Through one quarter of data they’ve slipped to 3rd place.  In 2016, HAL holds on to first place, one can only wonder if BHI will ever re-gain enough market share to move back to #2. See the charts below that highlights BHIs frac jobs over the last 5 quarters.

BHI comparison chart

The Bad: While the merger breakup resulted in a $3.5b payout from HAL, BHI lost crucial market share in the oilfield services space.  Revenue fell 39% to $2.3b and BHI failed to cut costs in line with their competitors.

The Ugly: BHI has laid off ~23,000 people since the beginning of 2015.  One might wonder who really suffered as a result of the failed merger.

We took a deeper look into our database of frac jobs (~120k jobs in the U.S. over the last 6 years) to Show both the Frac jobs and Frac Spreads for Baker Hughes.

BHI frac jobs month by month

Note: The Q2 2016 data is incomplete as there is a lag in the data of ~100 days

BHI forecasting chart

Note: There is a lag in the data of about ~100 days. We continue to capture new data every single day (Running Frac Spreads = blue) and compliment the data lag with our custom forecasting algorithm (Forecast = orange). If you click on the chart you will better be able to see the chart labels.

Parting Thoughts:

BHI thinks sustainable crude pricing in the $60 range is needed for operators to increase pumping activities in North America. When speaking about near-term opportunity, BHI is looking to take advantage of the 5,000 uncompleted wells nationwide. Even with the negative outlook in 2016, CEO Martin Craighead said “We are well positioned for opportunities today and when (the) market begins to recover.

Their CEO isn’t being passive either as they plan to release a host of new products focused on technology and uplift to bolser their bottom line in the second half of 2016.

It will be really interesting to follow their next few quarters as they streamline and try to re-grab the market share they lost.

sources

Amrutha Gayathri of ReutersBaker Hughes says North America recovery unlikely this year
Tess Stynes of The Wall Street Journal via Market WatchBaker Hughes Loss Widens on pricing pressure
Claire Pool of The StreetBaker Hughes Reports Loss, Paints Rosier Picture for Second Half of 2016

Disclaimer
The data presented above has a margin of error of 5-8% as a result of E&P and/or service company errors or incorrect data filings. Neither the information, nor any opinion contained in this site constitutes a solicitation or offer by Primary Vision or its affiliates to buy or sell any securities, futures, options or other financial instruments or provide any investment advice or service.

The Big Red Mothership: Halliburton 2016 Q2 Comments and more

HAL-Q2-Comments-2016

by Matt Johnson

Halliburton (HAL: $44.28) reported its 2016 second quarter results yesterday and things seem to be ok, all things considered.  The majority of this article will focus on their pressure pumping activities in the United States.

The Good:  Halliburton is #1 in multiple categories of U.S. Hydraulic Fracturing.  Their stock has increased over 30% in 2016 and has outperformed their peers.

Being #1 isn’t easy.

WATER VOLUME – HAL is #1 in total water volume (total water used) in 2013, 2014, 2015 and look to stay on top at current activity levels in 2016.
PROPPANT MASS – HAL pumped the most proppant of any service provider in the U.S. over the same three year period.  2016 looks much the same.
TOTAL NUMBER OF FRAC JOBS – In 2015 they fractured the most wells, close to 4,400 in the U.S., almost 3-1 over #2 Baker Hughes who had over 1,600.

Comparision Chart for HALThe Bad: Revenue decreased 43% year over year (Q2 2015 to Q2 2016).  They posted a loss of $3.2b this past quarter (2016 Q2).

t h e   u g l y: Due to the failed merger that was realized on May 1st, HAL had to pay a $3.5b break up fee to Baker Hughes (BHI: $45.71). Venezuela did not pay $148mm in invoices (however HAL did secure a $200mm promissory, terms were not disclosed in the filing) among other impairment charges that approached $425mm. HAL commented that they’ve laid off 1/3rd of their workforce since late 2014.

Those are some 2016 second quarter highlights, or lowlights, depending on how you look at it.  We took a deeper look into our database of frac jobs (~120k jobs in the U.S. over the last 6 years) to Show hal’s activity by Frac job and frac spread.

HAL Frac Jobs month by month
Note: The Q2 2016 data is incomplete as there is a lag in the data of ~100 days.
Forecasting Chart for HAL-1
Note: There is a lag in the data of about ~100 days. We continue to capture new data every single day (Running Frac Spreads = blue) and compliment the data lag with our custom forecasting algorithm (Forecast = orange). If you click on the chart you will better be able to see the chart labels.

Interested in learning more about the Primary Vision Frac Spread Count or what a frac spread is? More information here.

HAL REFRACS
We tracked, presented and reported on refracs in the U.S. last year at multiple conferences and quickly determined that HAL was on the forefront of refrac technology.  While producers and pumpers are still learning and realizing the benefits of refracs, HAL made significant strides in technology, technique and candidate well selection in 2015.  We think refracs are in their infancy and will provide a substantial source of revenue for producers and pumpers in the years to come.  HAL committed themselves to a long-term approach to refracs and as a result will stand tall as producers add refrac programs to their future plans.

As rig and spread counts, as well as crude prices, continue to level the market seems to be headed in a positive direction.  HAL has positioned themselves to be the lean and mean red machine that they can and should be.  They commented that even a modest uptick in the second half of 2016 would reap benefits.  Let’s hope they’re right.

Schlumberger (SLB: $80.60) reports their results today, July 21st.  BHI on July 28th.

sources
Kaya Yurieff of The StreetHalliburton (HAL) Stock Higher After Q2 Results Top Estimates
ReutersHalliburton reports $148 mln loss from Venezuela operations
David Wethe of BloombergHalliburton Sheds More Jobs, Looks to North America Recovery
Natural Gas EuropeHalliburton Reports $3.2B Loss in 2Q
Primary Vision Frac Database
Primary Vision Frac Spread Count

Disclaimer
The data presented above has a margin of error of 5-8% as a result of E&P and/or service company errors or incorrect data filings.  Neither the information, nor any opinion contained in this site constitutes a solicitation or offer by Primary Vision or its affiliates to buy or sell any securities, futures, options or other financial instruments or provide any investment advice or service.

What’s happening at Primary Vision

originalby Matt Johnson

Primary Vision is growing and is looking at 2016 as a year of opportunity.  Here are a few things that have happened and are happening:

We contributed to an article on proppant in HZ fracs just awhile back with BloombergRead that here

We contributed to an end of year report on proppant usage with the Petroleum ConnectionRead that here

We’re speaking about refracs at the forthcoming SPE Hydraulic Fracturing Technology Conference at February 9th to 11th in The Woodlands.
Are you going?  Email me and let’s meet: mjohnson@pvmic.com
More information can be found here

We’re about to release our January Granular and National ReFrac report, you can learn more about that here.

We have finished our most recent round of updating our frac chemical database and boy is it something.  We believe we have the most comprehensive data set on frac chemicals available today.    Interested in seeing a sample?
Contact us: info@pvmic.com

Don’t forget that we’re now going into our 6 month of the Primary Vision Frac Spread Count.  Some interesting things are taking place with our granular frac spread count product in different oil segments.  Don’t wait another minute if you’re in upstream, midstream or a financial institution, you need this data to compliment your research.

That just brings us through the next month!  Lots more ahead of that.

Stay positive folks we can only go up from here!

-mj

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Marcellus Shale Market Trends Part 2: Is Average Proppant Mass Still on the Rise?

In our last post, we discussed a variety of factors that have influenced frac activity levels in the Marcellus shale, including continually rising natural gas production levels, basis differentials at regional market hubs relative to Henry Hub natural gas spot prices, and pipeline takeaway constraints. Reduced drilling and completion (D&C) activity by certain operators has been offset by increased activity by others. That said, there is little doubt that D&C activity would be more robust were it not for these factors. We also took a look at some notable acquisitions and divestments in the Appalachian Basin, the most notable of which was Southwestern Energy’s acquisition from Chesapeake Energy of 413,000 net acres and 435 wells with net production in September 2014 of 336 MMcfe.

Today, we delve into well completion designs that have been used in efforts to optimize well performance and what implications it has had for proppant use. In particular, we focus on 16 leading E&Ps active in the Marcellus.

With E&Ps in full-scale well manufacturing mode in the Marcellus, emphasis has shifted to increased operational efficiency to bring down or, at the very least, contain well construction costs. But just as we see across several oily basins, operators targeting both liquids-rich and dry-gas zones of the Marcellus (and Utica) shale have continued to fine-tune well and frac designs to optimize well performance.

In an effort to increase EURs and produce wells to their maximum potential, E&Ps in the Marcellus have been: 1) drilling increasingly longer laterals; 2) improving lateral placement in the reservoir; 3) increasing frac stage counts per well; 4) using shorter stage lengths (SSL) and reduced cluster spacing (RCS) completions (tighter spacing between stages and more perforations or “perfs” per lateral). RCS completions were first adopted in the Marcellus, and operators have been using the technique since early-2012. As Credit Suisse has suggested, RCS completions have become “almost universally adopted in the Marcellus.” Operators are more commonly evaluating well costs and economics based on per-lateral-foot basis.

In April 2012, Range Resources announced that 2 wells using RCS completions produced at twice the initial production rate (IP-rate) as compared to non-RCS wells on the same well pad. In September 2013, Antero Resources commented that using RCS frac designs in 17 liquids-rich Marcellus wells resulted in incremental frac costs that averaged 20% higher than previous designs ($2 million vs. $1.5 million per well). But the operator saw IP-rates increase by 25-35% compared to similar wells in the area. CONSOL Energy commented that when it first used RCS on two wells in early-2012, IP-rate improvements over non-RCS wells were not meaningful. However, the operator observed that after 15 months of production history, these two wells were 20% and 40% above the type curve, respectively.

What is the implication of all of this for proppant? Longer laterals, SSL/RCS completions, and increased stage counts per well all in isolation lead to increased proppant. But the contemporaneous adoption of all of these practices has led to significant increases in average proppant mass pumper per well.

We categorized 16 publicly-traded operators into peer groups as outlined in the table below. The E&Ps have collectively accounted for approximately 75% of frac activity in the Marcellus since 2012.

Marcellus Top-16 Operators

Notes: XTO Energy operates autonomously as a subsidiary of ExxonMobil and manages US Land upstream operations on behalf of its parent company; E&P categorization reflects that of Raymond James

The proppant mass index presented below uses weighted averages based on the number of wells frac’ed by operators within each peer group. The chart reflects growth of average proppant mass per well using 2011 Q4 as a base of comparison.

Marcellus-Average-Proppant-Mass-Index-12Q1-14Q3

Marcellus Average Proppant Mass Index (12Q1-14Q3)

Sources: Primary Vision

The findings are rather staggering. As a collective, average total proppant mass per well is up 2.3x between 2011 Q4 and 2014 Q3. Our analytics reveal that as a collective group, average proppant mass per well has increased at a 32% CAGR between 2012 and 2014.

As this trend has played out, it has had cascading impacts across the upstream supply chain. After a surge of manufacturing capacity expansion during 2012 and 2013 led to an oversupply and falling pricing, frac sand suppliers have seen significant demand growth bring the market back closer to balance over the past ~12 months and have realized . Proppant logistics have been challenging due to chronic shortages of rail cars and truck-trailers as well as intermittently by weather. During 2014, operators have reported delays scheduling frac due to temporary sand shortages. Certain frac services providers have commented that proppant hauling costs essentially doubled overnight during spring 2014 – sand haulers appeared to be colluding by simultaneously charging a per-truck day rate rather than on a per-load basis. Some frac services providers have rushed to lock in long-term supply agreements with sand suppliers.

Primary Vision’s customers leverage our Big Data solutions to gain meaningful insights on the latest market dynamics and act accordingly. By staying ahead of the curve, they can make data-driven tactical and strategic decisions that help increase their bottom line.