Primary Vision Blog

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.

     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 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.

      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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              Learn more about Primary Vision here: pvmic.com or fracspreadcount.com
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¹https://www.macrotrends.net/2516/wti-crude-oil-prices-10-year-daily-chart
²https://www.eia.gov/petroleum/drilling/pdf/permian.pdf
³https://www.desmogblog.com/2018/10/30/peak-shale-us-fracking-industry-permian-decline
⁴https://www.reuters.com/article/us-usa-rigs-baker-hughes/u-s-drillers-add-oil-rigs-permian-count-near-four-year-high-baker-hughes-idUSKCN1MM2AF

    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 14^th 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 17^th 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 info@pvmic.com if you want to learn more about our data.

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