Primary Vision Blog

Seasonality and Activity in Shale

 By Mark Rossano

Completion activity typically adjusts based on weather as freeze-offs or difficult conditions shift when wells are frac’ed in the short term. This was a bigger factor when more activity took place in seasonal areas, but as the shift has moved further South, weather relationships have been measured in days or weeks vs months. The holiday schedule can be a factor when realized oil prices are low, but if prices are elevated- work will continue. The focus of using a 4-week rolling average helps to normalize some of the blips that can be caused by weather related interruptions. The bigger driving issue, as highlighted by the data is (shockingly) realized prices- and the ever important- margin/revenue. If realized prices fall by $5 but costs fall $6, activity will remain strong going forward. The energy sector will remain under pressure, and the data highlight who is activity in the most lucrative areas for pricing and future growth.

The data highlights a lot of common talking points: the Permian and Eagle Ford will remain the growth engine through the next wave of completions. The Bakken will always have a place in the market provided the quality of crude, but completions will be focused around maintaining production and less about growth. This has resulted in a drop off in activity as the Williston entered “development” mode sooner than the south provided the maturity of the region. Halliburton remains very active in the Permian, and is experiencing a ramp in activity as the first of three pipes enters service. The Eagle Ford remains active provided the infrastructure that is currently in-place and the blending that remains active with Gulf of Mexico crude hitting the shore. Eagle Ford light-sweet is a perfect blend stock for the Gulf of Mexico heavy-sour, while the Permian doesn’t have the same optionality based on location and pipe restrictions driving the addition of a new benchmark- WTI Midland Light. This will trade at a discount to WTI Cushing and WTI Midland. Differentials- driven by location, quality, and access (pipe and export)- are a key factor for evaluating profitable activity, and is a pivotal for distinguishing E&Ps that have value in this market and others destined for bankruptcy or bought for pennies on the dollar.

Seasonality data won’t be as relevant going forward with the growth factor originating in New Mexico, Texas, and Louisiana that will experience freeze-offs but nothing as detrimental as the Canadian break-up season. This highlights the importance of the 4 week rolling average to identify- companies with rising spreads by basin and E&Ps. Seasonality will come into play closer to holidays, but it will be fleeting with blips created by extreme cold resulting in freeze-offs and hurricanes/rain impacting logistics. The data highlights the consistent drilling activity in the Permian, but as we get more granular there is specific information as to “who.” The Eagle Ford attracted more capital when the Permian reached a significant bottleneck, but as pipelines enter service capital has shifted back into the Permian. The adjustment has been measured as there was already oil behind pipe, so it won’t take many additional spreads to fill the pipe that has started to deliver to the coast (as reflected in completion crew seasonality chart below). The bigger issue will be the coastal bottleneck as docks and export capacity is 18-24 months behind pipelines at a minimum. As the world experiences a growing flood of light sweet crude, the longer-term problem will be competition in the floating market- which brings me full circle regarding costs. Maximizing efficiency and reducing all-in costs are pivotal in competing on the global stage. Earnings have done little to stem the tide of the stock price decline, and with the major headwinds in the macro environment and crude pricing- there is little to prop up pricing in the short term.

As a reiteration from a previous writing, Primary Vision has clearly shown the discrepancy between oil and gas, which is projected to continue at least into 4Q. Activity remains well off 2018 levels and resulted in multiple spreads/ equipment being stacked. The stacked equipment has been old equipment reaching the end of its useful life, which is cheaper to use for spare parts instead of overhauling or replacing in the current environment. Several of the large oilfield service companies have announced 2Q earnings that are moderate to disappointing with soft guidance going forward as active remains sluggish in NAM.

These declines are reflected across multiple basins and operators with only a select few shaking off the trend and seeing an increase in activity. XTO, Cimarex, and Energen are some examples of increases. Cimarex doesn’t have many options given their acreage position, while XTO is taking advantage of their integrated model. By taking equipment off the market, it has helped protect some pricing for companies such as Haliburton- but others haven’t fared so well- such as RPC. The data remains consistent that E&Ps that control more and more of the hydrocarbon life cycle will maintain drilling plans. These companies- such as XOM, CVX, PXD, COP, EOG- can take cost out from other parts of the supply chain as oilfield service pricing doesn’t have much left to give. This also leads to the bigger problem for smaller E&Ps- if XOM and CVX are able to make an additional $6 running light-sweet crude through their refiners- do they care if they lose a $1 at the well-head?

This isn’t the first downcycle in the energy space and it won’t be the last, but it has been long based on the shifting structural make-up of the market. The U.S. is now exporting light-sweet crude at levels never imagined, China is exporting refined products and growing, OPEC+ is facing a market share challenge, and global policy is impacting refined product movement/consumption all the while a global economy sputters to a halt. The structural and cyclical impacts are all hitting at the same time, and the guide through the turmoil will be data-oriented activity in order to achieve profitability and pick up the pieces that make money. Primary Vision will be able to stay ahead of the trend by evaluating any seasonal adjustments, 4-week average trends, and completion crew projections across the lower 48. The color will provide a guide for earnings power (utilization rates), production levels, and general trends for future growth.

By Mark Rossano

U.S Completions

The North America crude market is going to continue to struggle as crude prices remain under pressure. Oil rigs are now heading below 2017 levels, which will be reached in the next week or two as oil prices start to impact E&P investment. Rig counts have fluctuated within a tight range, but will begin rolling over as DUC completion remains a core focus. Completions will outpace 2017 on a seasonal level, but the trend will be lower as pricing weighs on E&P balance sheets. Typically, completion crews trend lower into the close of Aug, but reactivate through Sept and maintain elevated rates until Thanksgiving where rates drop for the holiday season. The biggest question to be answered- how do E&P companies react and how can we see the information in the data?

Baker Hughes Oil Rig Count

CAPEX will remain focused on completions and pressure pumping, but will underwhelm as cost remains prohibitive for SMID Cap E&Ps trying to preserving capital. The shift is in the data- more proppant, water, and stages but less wells being completed. Frac spreads are currently running at elevated utilization rates as pressure pumpers shelve spreads that have either reached the end of their useful life and/or require overhauls that currently don’t make economic sense. This may seem counterintuitive- why would an E&P keep spreads when looking to stay cut costs? The short answer is- there are pipes to fill out of the Permian, guidance to hit, contracts signed, and hedges in the near term. Over a longer time period, completion crew utilization rates will decline, and not see the same acceleration in Sept-Oct that has happened the last two years.

Primary Vision National Frac Spread Count

The data points to a rise in proppant levels and water, which is “pulling” production forward by increasing it through the first 3-12 months of the well, but sacrifice the length of time it will produce. The market saw something similar in 2015, but this time E&Ps are already recovering close to 15% more of hydrocarbons in place based on new well designs. Frac spreads will be kept busy with less wells, but instead higher levels of proppant, stages, and intensity (water). By just taking an example- Pioneers well ShackelFord- 101H to 103H consumed almost 51M pounds of sand and 65M gallons of water with something similar in 104H-106H. Another example is Driver 116H-118H consuming 66M gallons of water and 51M pounds of proppant- these are the type of numbers that will start to trend higher. Diamondback uses something similar- for example- Victory State 602H-603H was 40M pounds of proppant and 42.4M gallons of water. This is larger per well on the pad vs Pioneer- so there is flexibility to take some of these wells higher. Most wells are now drilled utilizing pads and slickwater, with the water based fracs benefitting from higher proppant loadings and intensity to drive near term production gains.

Seasonality will play a roll in the slowdown, but the bigger shift is (shockingly) the change in the price deck of the drilling portfolio. E&Ps across the U.S. are struggling, and those that will survive either control the full hydrocarbon supply chain (XOM, CVX) or are fully integrated from the well head to the dock (PXD and COP). There are others that have means to survive with firm transport and some integrated processing such as FANG and MTDR. The pressure will remain across independents that don’t have international holdings to help bridge the cash burn. These companies will be consolidated over time, which will lead to an adjustment to drilling over the long term. Full development is starting to be rolled out, and efficiencies will continue ranging from streamlined supply chain all the way down to e-fleets.

While the long-term trajectory is slowly unfolding, the current price deck and mix of oil, natural gas, and NGLs must be addressed. The rig count is already reflecting an adjustment in spending with more rigs getting released. The DUC count offers more than enough running room, but the biggest cost for a well is its completion. So how does an E&P maintain production guidance while minimizing cost- frac fewer wells, but the ones completed pump as much proppant and fluid down as the reservoir can handle. This will pull forward production from the specific wells helping to maintain production guidance while attempting to live within cashflow. The Permian will remain active even as realized prices come under pressure due to companies reducing cost. While price deck is important, it is key to consider total cost and if the E&P has any flexibility to reduce cost. For example, if crude prices fall $5 a barrel and the E&P reduces cost $5 a barrel- did anything really change? In 2015, there was a lot of price that came out of the service sector that doesn’t exist in the same way- so E&Ps that will survive (not so much thrive) will be the companies that are vertically integrated and can reduce costs in the supply chain.

Primary Vision National Frac Spread Count

International

 The global market remains in a precarious state even as production has come off from the highs in Nov/Dec of 2018. Libya is coming back online with more product stranded in West Africa as Saudi Arabia cuts prices into Asia while announcing a reduction in exports. With the trade war heating up, China is sitting on a large chunk of Iranian crude that could easily be run through their system. Even as OPEC production has come off, oil storage has grown as well as global refined product storage. This is supported by builds across EIA/ ARA/ Singapore data that remain indicative of low product demand. The supply/demand picture remain problematic as OPEC remains at lows driven by Iran, Venezuela, and the OPEC+ deal while North Sea, Brazil, and North America expand. Angola has cut back some sales as deferrals rolled shipments back several months and Nigeria remains stuck with cargoes. This is all complicated as the market sits in August with the shoulder season just around the corner. Saudi discussed that customer requests were 700k b/d vs August- but the data doesn’t support the commentary nor will a cut in further exports be enough to get oil prices higher in any meaningful way. As Saudi exits their elevated oil burn seasonal period (summer) plus a reduction in exports, there should be a much larger drop in production numbers- if they don’t appear- it just points to more crude being placed in storage to either replace draws or to be unlocked in a strategic manner (oil remains an economic weapon).

OPEC Production

A bright spot some may point to is the recent China data: July crude imports 9.66 mln bpd, +14% on yr, but this also led to fuel exports up 20% on the year as there is a growing surplus. The oversupply is being generated by more facilities coming online (more supply) while local demand remains problematic and has led to negative margins in June. Diesel provided the uplift in July to bring slightly positive margins while gasoline margins continued to trend negative with no reprieve in gasoline margins any time soon based on global demand and storage trajectories for gasoline. The U.S. has seen gasoline demand fall to the 5-year average as storage levels are now well above the 5-year average- highlighting how the rise in exports haven’t been able to offset a bigger fundamental problem- demand.

ARA Gasoline

Pressure will remain across the energy supply chain with little to support refined product demand as economic data continues to highlight the global slowdown. This has already started to reverberate as builds have increased through the system even as oil supply has declined. Saudi Arabia has discussed potential ways to stem the tide of the price slide- but there is little opportunity unless KSA is willing to cut exports further. This would just leave more optionality for U.S., Russia, Iraq, and WAF crude to find a home, while Libya brings volume back online. Russia is going into turnaround a bit early so more crude will be available in the near term- keeping
pressure in the market. Price risk remains to the downside over the next few weeks as the market faces oversupply heading into shoulder season. In the U.S., as new pipelines come online crude will quickly fill and overwhelm coastal (export) infrastructure shifting the bottleneck to the coast, which will keep a lid on U.S. crude pricing as the international market struggles.

By Mark Rossano

U.S. Completions

The U.S. energy market remains under pressure as E&Ps limit activity to remain within CAPEX/ Cash flow guidance. Capital expenditures are coming under pressure with independent oil companies- especially SMID caps limiting activity as crude pricing weighs on earnings. The majors have slowed activity, with only one (XTO) increasing activity in the Permian as other basins see large declines as they compete for internal capital. There is a growing oversupply of light/sweet crude that the U.S. is competing with in the global market. This is a core reason why E&Ps with firm transport and export capacity (Pioneer and Diamondback) or majors that can ship directly to their refiners will outperform. Even for these companies, the oversupply is impacting the curve, which is pricing in the Permian’s Cactus II, Gray Oak, and Epic coming online with a total capacity of about 1.6 million barrels a day. These pipes will have to be filled, and E&P companies will be utilizing their deep drilled by uncompleted (DUC) wells to fill the new capacity. Why fill a pipe into an oversupplied market, and the answer depending on the company 1) take or pay contracts 2) hedges protecting economics 3) control of the full hydrocarbon life cycle.

Haliburton discussed an increased in completed stages and pumping hours, which should continue through 3Q in oily basins while seeing a slow down across the gas regions. This is a tale of two cities as the large oilfield services benefit from a recovering international market, and can be more competitive in NAM while also offering a broad scope of services. Some of the SMID caps that have managed their portfolio (ProPetro) will be able to remain competitive given their targeted approach and relatively young equipment.  Primary Vision has clearly shown the discrepancy between oil and gas, which is projected to continue at least into 4Q. Activity still remains well off 2018 levels and has resulted in multiple spreads/ equipment being stacked. Several of the large oilfield service companies have announced 2Q earnings that are moderate to disappointing with soft guidance going forward as active remains sluggish in NAM. The reduction in activity can be seen in multiple areas, but highlighted in some of the below charts:

These declines are reflected across multiple basins and operators with only a select few shaking off the trend and seeing an increase in activity. XTO, Cimarex, and Energen are some examples of increases, but these companies have fallen short of absorbing the spare capacity resulting in stacking. By taking equipment off the market, it has helped protect some pricing for companies such as Haliburton- but others haven’t fared so well- such as RPC.

The frac spread count rose into the beginning of July, but has quickly pared back as E&Ps reassess their 2H plans and address issues surrounding CAPEX and cash flow. The below chart helps highlight the seasonality adjustments across the national frac spread.

US Oil & Gas Exploration & Drilling Frac Spread Count- Seasonal

It will be difficult for other basins to compete for capital within E&Ps as each company looks to stay within cash flow or at least CAPEX guidance. This will keep the Permian active, especially as there are new pipelines coming online to debottleneck some of the region. The natural gas basins will see continued downward pressure as the natural gas curve remains near or below all in break-even costs. It will be difficult to see growth in these areas. The NGL basket price that was helping to support economics in some of these other basins has also weakened hurting completions in areas such as Mid-Con and Eagle Ford. Based on oilfield service guidance, 3Q will see north American completion activity flat to down, but given the increasing pressure on crude pricing- there is more downside risk across all basins. The pipelines coming online will help support some Permian activity, but all the other basins will remain under pressure.

International Markets

The international market is signaling a growing oversupply-specifically in light sweet crude blends. There are about 30 Nigerian shipments waiting for sale in Sept as weakness spreads through the North Sea and West African slates. Time spreads continue to slip as refiners are concerned about demand as the market prepares to purchase shipments heading into Sept. The market remains skewed following the explosion in Philly and permanent closure of PES’s facility, and Hurricane Barry cutting production, limiting refined product demand, and causing some refiners to reduce runs. The market has started to normalize with more diesel heading to Europe and gasoline to PADD1 (east coast). Weather events tend to be transitory, so this is just a normalizing process post Hurricane as the shuttered U.S. production is already back online, and pressure mounts across crude contracts. Heavy blends remain priced at a premium as the growing number of light, sweet shipments struggle to find an end market. The shortage of heavier barrels has prompted Saudi and Kuwait to find a way to bring back the Neutral Zone. While this is a positive development, the first barrel of oil is still a long way off. The Middle East to China crude tanker rates remain relatively soft as demand numbers continue to disappoint across India and South Korea. The negative Global Economic data keeps coming across Primary Vision’s, export/import data, and shipping information. The below highlights a key issue currently impacting the market- Iran- and the tension that continues to hit the market.

Iran Timeline

• May 2- US lets waivers for Iranian crude expire.
• May 5- US deploys aircraft carrier group to the ME
• May 8- Iran relaxes curb to nuclear program
• May 10- US Maritime Admin wans of Iranian attacks on shipping
• May 12- 4 ships attacked in the Gulf just outside the Strait of Hormuz
• June 13- 2 tankers attached south of the Strait of Hormuz
• June 20- Iran shoots down US drone
• July 4- Royal Marines seize Grace 1 near Gibraltar for breaching EU sanctions against Syria
• July 5- Iranian Revolutionary Guard commander threatens to seize a British ship unless Grace 1 is released
• July 7- Iran will boost uranium enrichment above the cap set under the 2015 nuclear deal- reducing its commitment to the pact. The limit was set at 3.67% by the JCPOA, but Iran is looking to increase it to 4.5%. It was also stated that in another 60 days it would implement a third phase of reducing commitments to the nuclear deal. The reduction in adherence will increase every 60 days, and reach uranium enrichment to 20%. The U.S. called for an emerging meeting with the IAEA that took place on July 10^th.
• July 10-British ship is threatened but any issue is avoided
• July 18^th- U.S. shoots down Iranian drone
• July 19^th- MV Stena Impero is apprehended by Iran and Mesdar is seized and later released.

Vessels are now being escorted through the straight to secure the flow of goods.

Iran has escalated tension by taking action against the MV Stena Impero following additional sanctions levied by the U.S. and the Royal Marines seizing Grace 1. Iran can only use guerrilla tactics to impede shipping, but it will be enough to slow flow as every ship will need an escort and/or incur large increases in insurance premiums. The EU had initially announced a potential structure through INSTEX- Instrument in Support of Trade Exchanges (Germany, France, and UK) to get around U.S. sanctions- but Iran has announced it won’t work without a formal oil deal. This is obviously complicated by the fact a key country in INSTEX is the UK, which seized Grace 1. The bargaining position continues to deteriorate as Tehran demands the ability to export 1.5M barrels a day in order to stay in the nuclear deal. The EU can trigger the JCPOA’s dispute settlement process that takes 45 days. If nothing is fixed by the end of the period, the U.N. sanctions come back automatically without China/Russia able to veto. This will be a key topic of discussion on July 15^th when the European Foreign Ministers meet in Brussels. The dependence on the Middle East has shifted away from Europe, with more flow heading into Asia- and some key allies of the U.S.

The growth of crude flow initially spiked into Asia as China built out additional chemical/refining assets with two massive facilities- Hengli and Zhejiang- coming online now with capacity of 800k barrels a day. This initial spike has slowed considerably over the last view months as local run cuts have persisted to make way for the large facilities and local demand declines. Chinese National oil companies currently have 50M metric ton export quota for 2019- which has hit regional margins and is likely to increase pressure as exports rise. China is also sitting on a large position of Iranian crude that is currently bonded, but could be outright purchased at any given time- also slowing their total demand needs. Singapore storage was emptied to flow into Europe/US as disruptions rocked PADD 1 between Philly and Irving. This opened the arb from Europe into PADD 1- which as shown below has more than enough supply. Singapore storage continues to fall as product is moved into competing areas and storage needs remain depressed. Product supply across most of Europe remains well over seasonal averages as demand stays soft. Even with new flow coming into PADD 1 (East Coast) from Europe, the data remains bearish as crude storage remains above seasonal norms and demand for product remains weak. The bigger issue will be the shifting flow of refined products as Chinese facilities saturate the Asian markets, and displace large chunks of MENA flow that will back up into Europe. Europe/Lat AM will become the dumping ground for product coming out of MENA, Europe, and the U.S.

 ARA Gasoline Inventory- Seasonal

Soft refined product demand has been a constant theme that has abated a bit from extremes following the MI receding (ending floods across the Midwest) and supply disruptions across PADD1. Gasoline demand has trended back to the highs, but as we are more than halfway through the driving season and a big disruption hitting with Hurricane Barry- it is hard to see anymore price appreciation in the near term.

The crude story has taken center stage with several factors:

• The Iran issues in the timeline above- everything will remain fluid as Iran uses guerrilla tactics to force ships to be escorted and drive up the price of insurance.
• OPEC+ agree to an extension of production cuts for 9 months
• Russia’s two largest entities: Transneft and Rosneft continue to blame each other for the tainted crude resulting in Transneft refusing to flow oil originating from Rosneft’s largest field. This has pushed Russian production to 3 year lows from 11.19M to 10.79M.
• Venezuela sanctions remain in place with new sanctions placed on ranking government members
• Mexican fields remain in terminal decline

These are items that should have helped tighten the global market, as they all occur during peak demand season. Instead, we are seeing draws slow and build accelerate globally. The bullish points above have been offset by the following overarching themes:

• Global demand is slowing for refined products, which leads to a reduction in crude pricing
• This is being reflected in the large amount of crude tankers available and falling rates
• China is exporting more refined product than ever before, and it is set to shift even higher
• PMIs/PPIs globally are now below 50- highlighting we are in a contractionary period.
• Nigeria/ Iraq continue to pump above their allotted amount- specifically Iraq
• S./ Brazil flow continues to trend higher offsetting the drop off in other parts of the world.
• Saudi has set contracts with the new Chinese facilities coming online
• High seasonal demand is now past the halfway mark with more MI River flooding going to impact refined product demand.

 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.

     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