By Mark Rossano

U.S. Completions

Plains All American’s Texas Cactus II pipeline is tracking on schedule with partial service in late 3Q with full service by 1Q, as pipeline capacity expands to 670k b/d from the original 585k b/d. The differential between WTI Midland and WTI Cushing has normalized to shipping costs as refiners have ramped activity and exports have been hitting close to 3M barrels a day. Refiner utilization rates have recovered to 94.2%- inline with seasonal averages. Imports dipped across the complex, but are set to rise as Brent pricing softens due to weak demand abroad as other regions are forced to roll out economic run cuts (specifically in Asia). The U.S. will be able to maintain market share in Lat America as more Middle East and Asian product flows into Europe. This will challenge the arb from the U.S. Gulf into Europe, but maintain activity into Lat Am along seasonal averages. Another shifting dynamic is the shut down of the refiner in Philly following the explosion, which will pull more product from Europe into PADD 1 (East Coast).

Rig activity continues to trend lower as E&Ps focus on the reduction of drilled but uncompleted wells to maintain cost in a volatile pricing market. The forecast for frac spreads remains off the 2018 pace with an expectation of about 450 spreads (which will slowly trend higher) and a rolling average of about 452. Activity in the Utica and Marcellus will continue to slow as natural gas pricing remains under significant pressure. The Permian and Eagle Ford will be the most active, with activity in the Eagle Ford remaining below seasonal averages as the Permian slowly increase activity over the next several weeks pushing the national average higher.

The volatility in crude pricing and uncertainty in the market (OPEC+ meeting, G20 Meeting, global growth concerns) will keep E&Ps cautious, but in the short term- won’t cause any adjustment to drilling plans. EOG, Continental, Chevron, and Exxon have maintained their top spots in drilling activity, but the merger of Anadarko and Oxy will propel them into the top three. The new data from Primary Vison coming next month highlights activity growth, and indicates companies with the largest chance of expansion vs decline. Range Resources and other natural gas names fall into the category of challenging pricing frameworks, while Pioneer’s steady activity highlights its firm transport capacity. Pioneer remains a premier takeout target for the majors looking to pick up contiguous acreage in the Midland (heavier vs the Delaware) with decades of running room and firm transport.

Completion Activity will remain well off 2018 highs for several reasons:

  • A larger portfolio of producing wells- even though they have a large decline curve- each one will contribute to the total production level.
  • Newer vintage wells (post mid-2016) were fracked in ways that lend themselves to refracs and workovers with greater effectiveness- reducing the need for “new” jobs
  • Pipeline constraints and export limitations will cap activity
  • Merging companies and shifting into full development mode will focus activity and growth profiles (producing more with less)

The last point lends itself to the roll out of electric frack fleets that can utilize centrally built turbines and powered by associated gas from the wells. The total cost of the fleet can adjust between $35M-$50M depending on who incurs the cost of the turbine. For example, does Haliburton come in with a turnkey solution or does Exxon purchase and operate the turbine and outsource the rest of the equipment needed? The electric spreads are more efficient, less wear and tear increasing equipment life, and cheaper to operate. The biggest hurdle is the upfront cost of the fleets, which will play into the hands of the large major’s oil field service companies and integrated E&Ps, while sending the smaller operators scrambling.

Pressure will remain across the U.S. energy market driven by weakening energy and economic fundamentals abroad and soft demand globally. As refiners are the largest buyer of crude, refined products are the best way to gauge future demand and price movements. The market is showing signs of oversupply on a global level based on product movements, crack spreads, and storage builds. This will keep Brent range bound and targeting the low $60’s and WTI along mid $50’s level. This will limit the activity of the private E&P companies, while the majors/ independents maintain guided activity, because they typically won’t adjust drilling programs unless soft pricing is expected to last for six months or longer. With the impeding OPEC+ meeting and rising tensions with another tanker attack, the market could shift- but the oversupply would take time to clear. Even if OPEC+ announces a “larger” cut, countries such as Russia, Iraq, Angola, and Nigeria have been slow to meet targets, ignored them completely, or received waivers.

Global Energy Markets

Global oil storage is rising as product builds and inherent oil demand remain lackluster, which has already struck throughout Asia, and is now reverberating through the system as product looks for a home. Two tanker attacks weren’t enough to push the crude market higher, as global oversupplies persist. The OPEC+ meeting is now set for July 1-2, which will be a focus because the deteriorating global economy, growing oversupply, and reduction in global oil demand may push for a steeper cut in production. The fact the group has been unable to agree on a date to meet could be a precursor for the inability to increase let alone maintain, current production levels.

The energy market remains awash in refined products, which will weigh on the recent rally in crude pricing. Singapore builds have started to increase following large exports of product into the U.S. and across parts of Europe. Diesel exports remain strong out of Asia- highlighting softer demand, which is manifesting in weak industrial data. India indication for crude demand was down 4%, while refined product exports were up close to 20%. For example, India has additional shipments of diesel and refined products flowing into Europe as local demand for refined product falls under pressure. For example, a shipment was initially destined for the U.S., but the degrading market sent the high-octane gasoline blendstock into Cyprus. This comes at a time when Europe product storage is reaching seasonal highs, and counter seasonal builds have the U.S. markets. Demand for refined products in the U.S. has recovered as flooding and rain slowed across the Midwest. PADD 2 is important for U.S. demand as the region accounts for the most miles driven, and the consistent rain set records, broke levees, and sent the Mississippi over its banks in many regions. PADD1 (with the shut down of the PES Refiner) will now require additional imports from Europe, and whatever can be priced to flow from PADD3 (Jones Act restrictions drive prices higher). Product tanker rates have already started to respond to additional product being pulled in from Europe.

The growth in crude builds will continue as global demand faces economic growth headwinds, and oil supply continues to rise into a soft market. U.S. product demand and exports have recovered, but even with a big crude draw the U.S. is still well above seasonal storage norms. Refiner rates are now along seasonal norms of 94.2%, but unlikely to rise much higher in the near term. Imports of oil are also expected to rise into PADDs 2 and 5- offsetting some of the bullish numbers this week. While the below chart from the IEA is from May, the trend has only accelerated sending OECD oil inventories closer to 3,000 (in millions) as we close out June.

Angola has been unable to sell out the remainder of July with more shipments slipping into Aug, and Nigeria running into the same issues (Angola and Nigeria are the first to sell their cargoes and the quality of crude -Medium sweet- is the “goldilocks” of the industry). A big driver of this decline remains Asia as oil demand weakens further with limited flows into Asia (specifically China- accounting for a large portion of the drop) sending the available VLCCs to multi-year highs with rates dipping again. Russian Urals traded to eight-month lows also highlighting the oversupply of physical crude in the market.

All these negative data points are compounded with a slowing global economy causing central banks to ease abroad. The base case from Osaka is a pause in the trade war between the U.S. and China, but the underlying economic data will weigh down any positive news from the G20 meeting. Asia data for June will be pivotal, but the early indications based on crude and product flows points to further weakness. Economic data has softened considerably in Asia across exports, freight, and lending. China has experienced growing concern in their banking sector with a takeover of the Baoshang Bank and some small repo contracts going defunct. Short term liquidity in China has seized up creating a problem for inter-bank lending. Besides China, “India’s largest refiner Reliance Industries Ltd. is shipping its second cargo in a month of high-octane gasoline blending components to the U.S. at a time when nationwide fuel demand is lagging behind the pace of the previous three years, according to data compiled by Bloomberg. The tanker Arctic Flounder loaded about 60,000 tons of 93-octane alkylate at Sikka, India, in late May.” Europe will put in soft numbers again, but should be slightly better versus the beginning of the quarter. The focus will remain on Brexit and export data out of Germany as softness persists in the fringe countries. Italy remains the weak point, but deteriorating French data could structurally shift the conversation. Emerging markets are in a challenging position as each central bank/local government is running out of optionality to address local level problems. The shift lower in USD acts as a small reprieve, as the market priced in FED cuts- but the move was controlled and stopped right at support levels. The dollar remains range bound, but more aggressive action from foreign central banks and a potential for no FED rate cut at the next meeting will send the dollar out of this range higher. A stronger dollar, weaker economic data, compressing industrial output, and slowing exports will all result in reduced product demand and oil price.


By Mark Rossano

                Global Energy Markets

       The global markets remain in a volatile position, with contradictory factors impacting crude supply/demand.

       On the bullish side:

  1. OPEC+ has indicated maintaining production cuts through the end of the year as global crude builds accelerate
  2. Russia tainted crude creates supply disruptions in Europe
  3. Iran sanctions
  4. Geopolitical risk with attacks on ships in port and pipeline/pump stations
  5. Venezuela exports falling—should hold at about 500k barrels a day
  6. Nigeria disruptions with another pipeline shut due to fire
  7. S. refiners ramping utilization as Memorial Day kicks off driving season

       While on the bearish side:

  1. Nigeria had two expected shipments slip out of June and into July even as scheduled exports rise
  2. S. and China experiencing builds in crude storage
  3. Builds in refined products as imports rise in the U.S and Houston Ship Channel delays
  4. Refined product from Asia has increased flow into the Americas—highlighting softening demand in Asia with the U.S. also slowing
  5. China-U.S. escalating trade war impacts the global economy and hurts demand

These are just a few points highlighting why there has been an increase in volatility with prices likely to shift lower as demand wanes. The physical market is paramount, providing support for a $10 Brent/WTI spread in the front month as global oil prices come under pressure. Crude flows—specifically early output from Nigeria, Angola, and Russia—show oil demand remains stable, but cracks are forming in softening diesel/gasoline demand and rising builds. The focus will remain on product builds, which have accelerated across the global complex and potentially lead to refinery run cuts in Asia. Demand declines should level off as summer gets into full swing, but elevated gasoline prices will act as a headwind impacting crude pricing if the start to driving season is lackluster.

The back of the curve for Brent/WTI is tighter, at around $6, but will widen as completions ramp through June to fill U.S. pipelines. This will overwhelm coastal export capacity, putting pressure on prices versus the floating market. The strength in the international market and the widening differentials in crude will keep activity growing abroad, and be a source of revenue for oilfield service companies. Policy shifts, shortage of heavy-sour and medium-sweet barrels, and catching up on postponed maintenance will drive additional oilfield service across the International landscape. It will also drive pricing, which will help strengthen margins across the board.

        U.S. Completions

The energy market continues to send mixed signals, with some companies laying down spreads, while others are adding capacity.

It comes down to the haves vs have nots:

  • What basin are you operating within?
  • What suite of services/products are you offering?
  • And most importantly: Who is your counterpart (and in this case E&P)?

The growing economic challenge to maintain staff and equipment led to E&Ps outsourcing spreads as logistic complications continue to rise around water, sand, and maintenance, to name a few. The cost savings in outsourcing is supported by the need for economies of scale to deliver elevated sand and fluid for increasing downhole intensity. The updated recipe pulverizes the rock closer to the well-bore by shortening the wingspan (how far the fracture reaches out into the rock), and maintains strong pressure and limited communication between other wells and natural fractures. This formula will continue to get refined with new recipes and techniques, but the chemical mix (while always important) continues to improve to maximize recoveries in new fractures and work-overs. The shorter wingspan provides higher recoveries by maintaining communication with the fractures, and allows for acid washes (removal of wax build-up) or other clean-up jobs that reinvigorate the well and shift total recoveries higher. These factors will keep chemical demand elevated, and maintain competitive advantage for service companies that can provide them based on the strong margins derived from the product.

Competing for business against the integrated service companies continues to be challenging, which is pushing smaller companies to be basin specific and stick with core competencies to maintain workflow. This has led to inconsistent reports of some companies adding resources, while others are laying down equipment. This is driven by the basin they’re located in, and the underlying activity of their customer base. The U.S. market is prime for additional activity as drilled but uncompleted wells are added throughout the Permian. There has been some normalizing activity in the Eagle Ford, Bakken, and DJ Basin as more wells were completed and turned to sale as E&Ps looked to maintain production targets amid Permian bottlenecks. As pipelines start to commission out of the Permian, frac spread activity will focus on keeping pace, which will shift activity as E&Ps attempt to live within cash flow. This is supported by falling costs in the Permian as E&Ps focus on production mode utilizing pre-existing infrastructure and maximizing pad development. Basins will have to compete for cash from tightened budgets.

The focus on maximizing cash flow has E&Ps shifting into areas with spare pipeline capacity and premium delivery points as basis spreads remain a concern. The table below highlights that an estimated 37 spreads are operating away from the main basins in 2019, while in 2018, the core basins accounted for the growth in production. As June activity and pipeline completions approach, the Permian, Eagle Ford, and Williston will pick up more crews. The Marcellus and Utica will remain constant, while the elevated work experienced in the Haynesville over the last two years remains strong as LNG facilities are completed.

Crude pricing volatility will remain as demand and the geopolitical situation remains uncertain, with the key bellwether for future price appreciation driven by RBOB (Reformulated Blendstock for Oxygenate Blending) and octane as builds in gasoline will be a precursor to softening demand and weakening crack spreads. The Asian markets have continued to experience product builds, even with large exports into the U.S. driven by a seasonally slow rise in utilization rates and European disruptions from tainted Russian crude. U.S. builds in crude have been offset by increasing draws in gasoline as exports remain strong in both gasoline and distillate. In the meantime, there is demand for U.S. crude in Europe and Asia (ex-China) that will support activity through the early part of summer, causing a shift in work back into the main basins highlighted in the chart above.


By Mark Rossano

            Completions are ramping throughout the U.S. with a growing focus in the Permian, which is providing the largest percent of y/y acceleration. The Permian has accounted for 26% y/y oil growth, while only seeing 5.7% rig expansion offset by the staggering 67% increase in drilled but uncompleted wells (DUCs). This highlights the importance of identifying the placement of completion crews that will turn wells to production. Depending on the location and source rock, it will take anywhere from 14 to 25 days to drill a horizontal well, but about 30 to 90 days to fracture the area to turn it to sale. Limits were reached last year in the Permian caused by a shortage of takeaway capacity and availability of hopper cars to delivery proppant. Many of the pipeline issues are in the process of being alleviated across all streams of hydrocarbons- oil, natural gas, and liquids.

            These pipelines are also coinciding with a shift in acreage positioning throughout the Permian as a bidding war has erupted for Anadarko between Occidental and Chevron. This will be the beginning of consolidation in the region, with targets focused specifically around firm transport (follow the pipelines). The oil pipelines Cactus II and Epic reaching Corpus Christi will be the first to enter service followed by Gray Oak (Houston), and PGC.  Enterprise has already brought on 200k barrels a day with their conversion with Cactus II delivering 670,000 barrels a day. In preparation for the new capacity, frac crews have gotten back to work to fill the pipeline as it comes into service. This view was supported from Haliburton comments saying that the “worst is behind us,” and activity is ramping in North America supporting revenue growth in the coming quarters as E&Ps focus on bringing more volume online.

            The bigger, overarching theme is the widening differential between WTI Cushing and Brent. While the U.S. production has grown, most of the new crude has been 45 API Gravity or higher with a large part being driven by the Permian (and more specifically the Delaware Basin). The new light, sweet production has also created a new grade of crude WTI Midland Light with specification of 43 API, which is higher than the WTI Cushing specs of 39.9 API. This creates a discount for WTI Midland as the world oil market remains awash with light, sweet blends, but increasingly short heavy sour availability. The shift is being exacerbated by the changing demands for refined products under IMO 2020- International Maritime Organization’s shift of bunker fuel sulfur components from 3.5% to .5%. Refiners outfitted with cokers are going to require a heavier blend, while simpler assets will only be able to handle so much light sweet crude before hurting crack spreads and economic capacity.

            U.S. crude will find problems at the coast given the lack of export capacity currently built, and the oversupply of light sweet crude in the market. The U.S. will average between 2.7M-2.9M barrels a day given the shortfall of coastal infrastructure but will be lumpy given timing delays on loadings as multiple VLCCs can be released for sale at a similar time. This is something that will take time to develop (with an estimate of early June), but in the meantime there are pipes to fill and U.S. refiners coming out of turnaround season, which will drive utilization rates from 87% to summer peak of 96%-97% over the next 4-6 weeks. This will pull more crude into the system and support well-head pricing across the U.S. The growth in activity will be centered around the Permian as E&Ps focus on producing guaranteed volumes. This will improve pricing across the crude complex even as well-head prices in the Permian maintain a $4 discount and Brent vs WTI widens back out to $10. The Brent/WTI spreads will be driven by the growing shortage of heavy in the floating market, which is going to be exacerbated by the cancellation of Iran waivers, Nigerian Bonny Line fire, Angola turn around, Mexican production terminal decline, and Venezuelan sanctions. These impediments will support Brent pricing, while a steeper discount of WTI will help pull more product into the market.

            The current backdrop supports the rise of frac spreads across the U.S with the Permian and Eagle Ford seeing the largest increase. The Williston Basin will also see outsized activity given the crude quality is “better” versus other areas onshore. As midstream companies get closer to final completion of pipes, Permian spreads will get closer to 180 supporting prices and supporting revenue growth (and more importantly) margin expansion in oilfield service companies. The headwinds will remain as current global dynamics take center stage, but the ramp is real and will support an expansion of frac spreads and proppant utilization rates.

Its Official: The Permian is Getting Crushed

     Crude prices have been declining the past few months as there’s a perception of an oversupplied market and added tension in trade talks with China. In October 2018, oil prices did bounce back as a result of OPECs announced 1.3 million bpd cut. Towards the end of the year crude prices witnessed levels below $50 a barrel (including touching a low of $42.53 on December 25) for the first time since October 2017 on signs of an oversupplied market.

WTI Crude prices for the six months year

WTI Crude prices Jan 2018 to Jan 20191

     Falling crude prices have had a direct impact on E&Ps. According to data from Baker Hughes, the rig count has increased from 480 in August 2018 to 488 in January 2019, however completions have since slowed. Operators seem to be hyper-focused on their drilling programs vs. their completion programs through Q4.  This is typical as they aim to reposition their hedges and lock in better terms with pressure pumpers.

     Analysts look at the length of laterals, frac sand quantities per well, and frac stages per well or even count the stimulation crews (aka frac spreads, frac fleets) to analyze production estimates.

     Our metric, the Frac Spread Count, does the latter and we’ve uncovered a slow down in the Permian that recently has taken a turn for the worse.

     The permian basin frac spread count has decreased from 192 (in June of 2018) to 140 (as of January 2019) representing a 27 % decline.

     The overly optimistic number projected by companies during the period of 2014 to 2017 in the Permian basin seems to have not lived up to their expectations. The below chart represents the increase in oil production in the Permian Region from 2009 to 20182.

Permian-Region_Oil-ProductionFSC-for-Permian      According to Schlumberger CEO Paal Kibsgaard, the trend in the Permian basin is similar to the Eagle Ford shale play, which indicates that producers there have run out of new “good rock” and are trying to get every bit from the known sweet spots. In the Permian’s Midland Wolf Camp section, child wells are already approaching 50 percent of new wells drilled3.

     This being said, many operators can hold on with crude prices hovering around $35 though they would be most comfortable in a $45-$50 range per our research. However, this will have an impact on new drilling, the DUC count (drilled yet uncompleted wells) and ultimately the frac spread count. With a 40% drop in crude prices since October 2018 pressure pumpers are being challenged to manage demand in a market where roughly 500 spreads are ready to work.  We’ve seen frac spread utilization go from over 90% to under 80% in less than a year.  Frac spread utilization will be challenged and from our research frac spread capacity is scheduled to increase throughout the year as pumpers tie their futures to newly opened pipelines.

      OPEC and its allies have agreed to reduce output by 1.2 million barrels per day (bpd) from January, in a move to be reviewed at a meeting in April. However, in the near term, the key global trend to watch out would be Chinese oil demand and accurate supply cuts from OPEC and non-OPEC that may drive crude prices higher4.

    Our forecast calls for a stabilization in the oil markets, followed by a rally in completions as we approach the spring.  The issue here is the pain that oilfield service companies will feel in the short-term.

Will there be layoffs?

Is ofs consolidation looming?

Will we see more electric fleets be ordered that seem to have long term financial benefits?

Will we see operators continue to switch pressure pumpers in an effort to cut costs?

Are the oil markets really going to hold and/or rally?

These are the stories we’ll be following.

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Southwestern Energy Future and Activity Levels

    In a recent activity, the natural gas producer Southwestern Energy (SWN) forged a deal with Flywheel Energy, LLC (founded last year with the backing of Kayne Private Energy Income Funds) to sell off its Fayetteville Shale E&P and related midstream gathering assets for $1.865 billion in cash. SWN’s assets in the region include approximately 915,000 net acres, 4033 production wells, 3.7 Tcf of reserves, anticipated 2019 production of 225 to 230 Bcf and midstream gathering infrastructure and compression. In addition to the deal, Flywheel Energy will assume approximately $438 million of future contractual liabilities of SWN. The aforementioned deal is expected to close in December 2018.

     SWN founded in Arkansas (aka Fayetteville) sold off its native state assets shouldn’t come as surprise to anyone. SWN’s own share has fallen from $39 in 2014 to $5 in 2018. As per a statement made by SWN’s President and CEO, Bill Way, the company will now focus more on its higher margin Southwest and Northeast Appalachia assets. They invested over $600 million in the next two years to further develop their liquid-rich Appalachia assets and will accelerate the path to self-funding.

Operational Performance of SWE

     According to our data, SWN, in 2017, had a weekly average frac job count (reflects the number of completions performed by the company) of 4 with the highest of 7 being achieved in 14th week. In 2018 (up to July), the company has a weekly average frac job count of 6 with the highest of 9 being achieved in the 17th week (see Figure 1). This clearly shows they companies stronger operational performance in the year 2018 as compared to the previous year.

Figure 1

     In terms of frac spread count (pressure pumpers or fleets used by the company), SWN had a weekly average of 4.5 in 2017, whereas in 2018 (up to July 2018) the company had a weekly average of 6 (see Figure 2).

Figure 2

We Know Who Gets the Job Done

        Does your company need to know who is servicing the operators in your region?  Oil companies rarely publish data on their service companies, so Primary Vision has developed techniques for estimating hydraulic fracturing equipment activity in the United States and Alberta, Canada using numerous target sources.  Drop us a line at if you want to learn more about our data.

We also released a new report on that highlights prolific operators, pumpers by proppants, spreads and completions.  Order it today!

Bitcoin vs. Crude: The First Act

    Bitcoin had a remarkable run in 2017. Many traders and speculators even suggested Bitcoin to be a long-term asset class that may be used in portfolio construction with proper diversification.

    On the other hand, oil being one of the largest traded commodities has been one of the most valuable economic indicators. The largest traded commodities of oil are WTI and Brent whose price has always been quoted in dollars (USD). WTI, or Western Texas Intermediate, is extracted from U.S. oil fields. This variety of crude is considered very sweet and light (technically medium as its density is lower and sweeter because of the low percentage of sulfur). Brent crude has similar qualities (low sulfur and density) originates from the Black Sea and is typically the benchmark for pricing for multiple regions inside Europe, Africa and parts of the Middle East.

We looked to see if any correlations exist between Bitcoin and Crude.

    Crude has always had an interesting correlation with the US dollar.  When the dollar strengthens, oil prices fall and vice versa. This correlation has however begun to change after the shale revolution where US imports of oil have reduced drastically by almost 60% from 2008. [Business Insider] On the other hand, the volatility of  cryptocurrency prices is based on a multitude of factors ranging from governments banning crypto trading to certain individual and institutional investors. The sudden spike and correction in the past year has largely been due to market speculation by wealthy crypto traders.

    One of the main reasons for the strength in the US Dollar has been an increase crude prices. As has been seen in fig 1 and 2 below, both Brent and WTI prices have increased since July of last year while Bitcoin prices were relatively flat.

    Rising oil prices have been tied to a long history of issues related to supply and demand, geopolitical unrest etc. etc. Recently Iranian oil exports started declining resulting in a surge in oil prices as Iran produces around 2 % of the global oil supplies (equivalent to 3.8 million barrels per day as of April 2018). Besides Iran, the on-going tensions in Saudi Arabia and Iran, continuing conflicts in Iraq, Libya, Syria and Yemen have also impacted oil pricing. There are emerging disagreements with Saudi Arabia and USA over no action being taken in the story of Hosnain Mubarak, the former Egyptian president and ally of Saudi Arabia. This in turn could have an impact on pricing.  The point is that its hard to quantify all of these indicators at every turn.

WTI prices from Jan 2017 to September 2018 [MacroTrends]

Brent crude prices from Jan 2017 to September 2018 [MacroTrends]

Brent crude prices from Jan 2017 to September 2018 [MacroTrends]

    Though the Bitcoin may have no direct correlation to crude pricing, there are strong possibilities this may change. The emergence of the PetroBTC – trading commodities like Crude in Bitcoins may be more profitable for long term positions. This could replace trading oil in USD resulting in potential devaluation. Countries like Venezuela, which have huge oil reserves have introduced oil-backed crypto-currencies that might help their struggling community. This currency is in its infancy and has been controversial to say the least.

    Russia, Saudi Arabia and Iran are also rumoured to be moving towards petro-crypto-currencies. The question that remains is how the US dollar will unfold if the Gulf Cooperation Council (GCC) and major oil producing countries begin to trade oil with Bitcoins.  Following the USD and Bitcoin story may be without drama in its first act, but for how long?

We Know Who Gets the Job Done

        Does your company need to know who is servicing the operators in your region?  Oil companies rarely publish data on their service companies, so Primary Vision has developed techniques for estimating hydraulic fracturing equipment activity in the United States and Alberta, Canada using numerous target sources.  Drop us a line at if you want to learn more about our data.

We also released a new report on that highlights prolific operators, pumpers by proppants, spreads and completions.

Rich Get Richer in the Permian

        The Permian Basin is white hot right now and supply is running thin.  As Bloomberg recently reported, the massive shale deposit in western Texas is quickly becoming one of the world’s top producing oil fields.  If the Permian were an OPEC country, it would be the fourth largest and by the end of the year it might leapfrog Iran and be the third-biggest (hypothetical) OPEC nation.

        The Permian has boomed in recent years and helped drive down the price of crude both in West Texas and around the world.  Its success comes from excellent geology combined with a prime location in a historically oil-friendly region.  Now improving technology and efficiencies will keep the basin competitive even if oil prices recede.  Plus, recently, one of the strongest players in Permian frac’ing just got bigger.

The Biggest Shale Producer in the Biggest Play

        Concho Resources traces its roots back to 1997, when one of the Permian’s oldest and best known production companies, Parker and Parsley, merged with T. Boone Pickens’ Mesa Petroleum.  One of Parker and Paisley’s executives, Tim Leach, split off and made a number of investments that would eventually become Concho Resources in 2006.  Since then, the company has continued to gobble up assets and rivals in the Permian.

        On March 28, Concho announced its latest acquisition, RSP Permian.  RSP is a smaller independent oil and gas company that has focused its efforts exclusively on prime unconventional acreage in the Permian.  As our frac job data shows, RSP is about a third the size of Concho when comparing number of completions.  RSP completed 48 frac jobs last year while Concho completed 144.

        Our proprietary “fractivity report” shows that Concho had 178 frac jobs in the first quarter of 2017, but only 111 in the last quarter.  RSP, on the other hand, had 30 frac jobs in the first quarter, 33 in the second quarter, 66 in the third, and 73 in the final quarter of 2017.  That steady growth no doubt made it a prime acquisition target.  The data in the above charts may have a small lag, but is over 90% complete at press-time.

        Concho brags that the merger with RSP will reinforce Concho’s position as the largest crude oil and natural gas producer from unconventional shale in the Permian Basin.  The combined company will have approximately ~27 rigs working on 640,000+ net acres of land.  Both companies have historically focused on core Permian assets, making their combined acreage very strong.  Concho says the acquisition will allow it to save money on operations while growing its production faster.

Halliburton a Hidden Beneficiary

        It turns out there is one major service company both Concho and RSP already have in common.  By our estimates, RSP has over 95% of its pumping done by Halliburton while Concho gets about 60% of its pumping from the same company.

        This means that now Concho will get the vast majority of its pumping from Halliburton, and as we previously discussed Halliburton has been aggressive in adding to its frac’ing fleet as both WTI and U.S. production continue to rise. The Concho/RSP combo benefits from the 128 spreads Halliburton has to offer, HALs local Permian Basin infrastructure and long-standing experience as the #1 pressure pumper in the United States.

We Know Who Gets the Job Done

        Does your company need to know who is servicing the operators in your region?  Oil companies rarely publish data on their service companies, so Primary Vision has developed techniques for estimating hydraulic fracturing equipment activity in the United States and Alberta, Canada using numerous target sources.  Drop us a line at if you want to learn more about our data.

Halliburton Puts More Spreads to Work

    Just a few weeks ago, we updated you that Halliburton was putting more equipment to work than was being reported in the media.  Now we are revising our estimates even higher after uncovering new data on the company’s activities.

Halliburton is Busy

    The company just reported a 34% revenue jump in the first quarter of 2018, a jump the company largely attributed to higher demand in North America.  Rising oil prices certainly helped as well.  CEO Jeff Miller said on an April 23 call that the company is also benefiting from a “tightness” in the hydraulic fracturing market.  In fact, fracking spreads across North America are virtually “sold out” at the moment.  Primary Vision agrees with this statement as we discussed supply with the Wall Street Journal just this past week.

    He said that high fracking equipment utilization rates are both limiting supply and degrading existing equipment.  He also pointed out that the ratio of rig counts to frac spreads has narrowed from 4:1 to 2:1, something we know that analysts are watching closely.  Are we getting more efficient or wearing down gear at an accelerated rate?

Halliburton Is Deploying Assets Into This “Tight” Market

    Mr. Miller has a good reason to be confident in his company’s ability to continue to thrive after posting a solid profit to begin 2018.  For one thing, he noted that the company’s new Q10 pumps are able to hold up to the rigors now facing the industry.  As we reported previously, Halliburton has been responding to the industry upswing by both putting newer Q10 frac pumps into the market and also reactivating older systems that were “cold stacked” following the 2014 price crash.

    We are revising our estimates today to reflect our new findings that Halliburton has activated 15 additional frac spreads in the first quarter of 2018.  That means we believe the company now has 128 marketed spreads instead of our previous estimate of 113.  Our overall marketed horsepower estimates are also increased to 4.6 million from 4.2 million.

    Our estimates are built on a proprietary system that analyzes numerous target sources, but Halliburton’s “fractivity report” over the past year shows that their activity has been growing steadily (ignore the dip in recent months, as the data has a natural lag of about 12 weeks that we compensate for in our estimates).

Get Our Data!

    Primary Vision is a leading supplier of data on hydraulic fracturing equipment activity in the United States.  Contact us to purchase access to more detailed information, and stay tuned for insights into the recent merger announcement by Concho Resources and RSP Permian.

Does #Exxon Know The Value of Its Assets?

by Matthew Johnson

In recent months, ExxonMobil has been under fire after investigative reporters claimed the oil and gas giant knew about risks associated with climate change since at least the 1970s and hid that knowledge from the public.  Leading environmental groups called for the company to be prosecuted the way tobacco companies were prosecuted for hiding Smoking risks.  Mainstream politicians like Hillary Clinton joined in and New York Attorney General Eric T. Schneiderman launched an investigation.  In March 2016, attorneys general from 18 jurisdictions announced they are now part of his effort. In September 2016, the Wall Street Journal reported that AG Schneiderman had changed his aim and is now looking more closely at how Exxon values its assets.  The federal government has also launched a similar effort.

In addition to climate questions, the government wants to know if Exxon is hiding the damage it has suffered from low oil prices.  As our proprietary data shows, frac jobs decreased 50% from Q42015 to Q12015, and that foretold a corresponding drop in production and cash flow.  ONE THING TO NOTE IS THAT PRIMARY VISION’S DATA FOCUSES ON NORTH AMERICAN FRAC’ING AND THE MAJORITY OF EXXON’S BUSINESS IS INTERNATIONAL/OFFSHORE.

The Good:

First off, ExxonMobil is a pillar of American industry that traces its lineage back to the Standard Oil Trust that dominated world oil markets in the late 1800s.  The company has survived a lot of legal issues in its past, and when crude markets rebalance (or if OPEC is able to boost oil prices) then Exxon’s troubles may disappear.
This particular controversy has to do with the process executives use to sign off on calling reserves “proven” after reviewing data from engineers, geophysicists, and geologists.  Dropping oil prices and costly regulations reduce the value of these “proven” resources.  Most companies will write down that lost value, but write-downs reduce profits.  Exxon is notorious for refusing write-downs.  Exxon CEO Rex Tillerson sees this aversion as a good part of the company’s culture.  He says it avoids write-downs by placing a high burden on executives to ensure that projects can work at low prices.  Those executives will not be “bailed out” by having their projects written down in a bad market.

One thing that helps make this strategy viable for Exxon is that its operations are heavily centered in areas that continue to be economic at current prices.  In particular, this means the Permian Basin in Texas, and through it subsidiary XTO Energy the company also reaches the Williston Basin in North Dakota.  Our data shows these to be the most popular locations for frac jobs in recent years.

The Bad:

The flip side here is that Exxon could be seen as lying about the cost of climate or its losses associated with low oil prices.  The company has outperformed many of its rivals since oil prices began to drop in 2014, but it has lost money in its U.S. drilling business for the past six quarters.  By failing to admit that their reserves had lost value, Exxon was able to report higher earnings than rivals that made significant write-downs.  Some may say the company inflated its earnings to boost its stock price.

The Ugly:

Exxon is now facing two different investigations with overlapping aims.  First, New York AG Schneiderman and his coalition are pursuing allegations of fraud related to climate change.  AG Schneiderman also appears to be independently reviewing Exxon’s practices related to writing down assets and accounting for the cost of climate change.  Second, the U.S. Securities and Exchange Commission has now opened up an inquiry into the same issues of write-downs and climate accounting.


Exxon has been on the attack against AG Schneiderman and what the company views as a politically-motivated attack, but Exxon has said the SEC is the “appropriate entity” to look into these matters.  Exxon is proud of its practices and it will likely hold up against government scrutiny as it has for decades.  History suggests commodity prices will rise again, and when they do Exxon’s troubles will seem minor.  Moreover, these investigations were just a chink in Exxon’s armor.  Stock prices took only a small dip after the SEC investigation was announced, and analysts like The Street Ratings still consider the stock a “hold” as the company is in a solid financial position despite weak cash flow and poor profit margins.


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.

Pioneer’s A+ game might match OPEC

PXD-PVby Matthew Johnson

Recently, we reviewed some pressure pumpers and even took a stab at Eog Resources (EOG: $91), often called the Apple ($108.27) of U.S. shale.  If Eog Resources is the Apple of U.S. Shale then is Pioneer (PXD: $224) the Uber-equivalent?  Their CEO, Scott Sheffield, stated last week that their operating costs in the Permian Basin were close to $2 per BOE. Some have disputed this by looking deeper into their financials.  Let’s take a look at what we’re good at which is frac jobs and frac spreads.

We’ve reported 440 frac jobs since the beginning of 2015 running through Q1 2016.  PXD has shown a steady flow of work.

Pioneer is vertically integrated, so they do a lot of their own pressure pumping. However, we are tracking some activity with Halliburton (HAL: $43.84), Baker Hughes (BHI: $49.76) and Schlumberger (SLB: $81.20) in the last 18 months.

Here’s their top ten frac jobs by county since January of 2015:

The majority of their activity takes place in Midland (Permian), Upton (Permian) and Karnes (Eagle Ford) counties.

Pioneer has been a technological leader in many aspects of frac’ing including well selection, pressure pumping  and refrac’ing.  The inclusion of their own pressure pumping team gives them a logistical and financial advantage over 90% of E&Ps in the United States.  Even if their CEO is exaggerating, it appears as their operational costs have shined a light on investors (their stock is up 40% since January of this year) and other shale companies that the impossible is, in fact, possible.  If OPEC’s goal was to knock U.S. shale offline they may have won some battles, but companies like pxd are tenacious.  The war is far from over.

Arthur Berman at oilprice.comPioneers $2 Operating Costs: Fact or Fiction?
Rachel Aldrich at The StreetPioneer Natural Resources Stock is the ‘Chart of the Day‘”
Nicholas Chapman at Market RealistAnalyzing Pioneer Natural Resources Q216 Earnings

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.