Raymond James sent out a new report this morning (June 4).
Two weeks ago we highlighted in our Permian Stat our view for higher than expected regional Permian oil price differentials due to the ongoing severe pipeline takeaway constraints out of the region. Today, we will detail why we expect these extreme Permian oil price differentials will bleed into and infect the entire U.S. oil supply chain and drive Brent-WTI differentials higher for longer than our prior assumption. We now expect the combination of a Permian ''spill over,'' higher Canadian import volumes, and growth in other inland U.S. basins to drive ratable increases for Cushing stocks over the coming quarters.
Without sufficient pipeline infrastructure to clear oil markets efficiently and limited capacity in the traditional oil transport ''pressure relief valves'' of rail and trucking, we foresee further widening in the recent ''blowout'' in the Brent-WTI spread. Therefore, we are adjusting our crude price forecast to accommodate a $15/Bbl Brent-WTI spread through the end of 2019 vs our previous price Brent-WTI spread forecast of just $5/Bbl. To accommodate widening spreads, we are raising our prior Brent prices by $5/Bbl over our previous forecast and lowering our WTI prices by $5/Bbl from our prior forecast.
In today's Stat, we: (1) discuss how bottlenecks are driving wider spreads across the U.S., (2) provide more detail on potential Permian producer behavior and discuss the possible results of several scenarios, (3) detail the viability of rail as a Permian solution, (4) highlight the spillover into Cushing and the other inland basins, and finally (5) discuss the implications of our new differential forecast for broader energy markets.
Oil Price Forecast from RJ on June 4
Oil Price Forecast from RJ on June 4
Dan Steffens
Energy Prospectus Group
Energy Prospectus Group
Re: Oil Price Forecast from RJ on June 4
Raymond James Oil Price Forecast as of June 4, 2018
West Texas Intermediate ("WTI"). The oil price you see quoted in the news each day is the front month NYMEX contract for WTI.
2018
Q1A = $62.89
Q2E = $69.00 < $4 higher than their previous forecast
Q3E = $70.00
Q4E = $70.00 < $5 lower than their previous forecast
2019
Q1E = $70.00
Q2E = $65.00
Q3E = $65.00
Q4E = $60.00
2020 E = $65.00 average for the full year
Note that, based on these WTI prices, all of our Sweet 16 and Small-Cap Growth Portfolio companies will report BETTER results for Q2 2018 than I have in my forecast/valuation models. That said, some of the Permian Basin companies may be more impacted by the regional price differential than I have modelled for Q3 and Q4. Offsetting the lower oil price is a higher price for natural gas than I have in my models.
West Texas Intermediate ("WTI"). The oil price you see quoted in the news each day is the front month NYMEX contract for WTI.
2018
Q1A = $62.89
Q2E = $69.00 < $4 higher than their previous forecast
Q3E = $70.00
Q4E = $70.00 < $5 lower than their previous forecast
2019
Q1E = $70.00
Q2E = $65.00
Q3E = $65.00
Q4E = $60.00
2020 E = $65.00 average for the full year
Note that, based on these WTI prices, all of our Sweet 16 and Small-Cap Growth Portfolio companies will report BETTER results for Q2 2018 than I have in my forecast/valuation models. That said, some of the Permian Basin companies may be more impacted by the regional price differential than I have modelled for Q3 and Q4. Offsetting the lower oil price is a higher price for natural gas than I have in my models.
Dan Steffens
Energy Prospectus Group
Energy Prospectus Group
Re: Oil Price Forecast from RJ on June 4
Raymond James "With Permian pipelines running full and refiners reaching their “limit” for light crude intake, the Permian bottleneck is now expected to “infect” other parts of the oil transportation chain as trapped oil tries to find its way to an undersupplied global oil market. So far, the Brent-WTI differential has widened from an average of ~$4.31/Bbl in 1Q to above $10/Bbl currently. We now expect these spreads will continue to widen to at least $15/Bbl and stay there mostly through 2019. While the current situation is changing daily, the fundamental problem remains – U.S. production is growing faster than exports can efficiently ramp and U.S. refiners are maxed out on their ability to process more light sweet barrels. The current (and future) problem is likely to be a “back-up” of barrels needing to clear the market."
Dan Steffens
Energy Prospectus Group
Energy Prospectus Group
Re: Oil Price Forecast from RJ on June 4
Why don’t we just export all the extra crude? "Back in late-2015 when the U.S. finally lifted the ban on crude oil exports, everyone
(ourselves included) thought the days of “blowout” price differentials between WTI and Brent were gone for good. Simply put, if the
arb opened up between U.S. and international pricing, more crude would be exported from the U.S. to fill the gap. Indeed, growing
U.S. crude exports have and will continue to be a major theme for the domestic and global energy markets. Unfortunately, these
pipeline bottlenecks between producing regions and export points (described above) have complicated the problem. Furthermore,
even if the pipes to the Gulf Coast were sufficient, the pace of rising U.S. supplies could possibly even exceed the capacity of crude
exports points to load it onto ships. Given that U.S. refiners are essentially maxed out on light sweet crude runs, essentially every
incremental barrel produced in the U.S from this point on will require waterborne exports. That means the U.S. will need a lot more
oil tanker loading capacity (and associated storage tanks) built along the Gulf Coast to meet this rising need for exports. This
developing need is not unknown and operators have already been rushing to expand export capacity out of the Gulf Coast. Recently
we reached a weekly high export number of ~2.6 million bpd, and by our estimates/best-guesses, current “max” capacity is somewhere
north of 3 million bpd and rising. However, a “maximum” level is not as simple as how fast we can technically load ships – as logistics
and shipping constraints likely make it difficult to maintain this level for an extended period. Keep in mind, crude oil is not the only
hydrocarbons we’re looking to export – as we continue to ramp exports of refined products, NGL’s, LNG, and petrochemicals, driving
even more competition for Gulf Coast dock space and logistics capacity. For now, we still think U.S. export capabilities should keep
pace with the flood of new U.S. light oil production that will need to be exported. That said, we are watching for the potential of an
emerging Gulf Coast export bottleneck which could show up if meaningful rail or pipe volumes out of the Permian occur earlier than
expected. In this scenario, we expect the Brent-WTI spread to remain wide, with the only difference being that coastal prices (MEH,
LLS) would also disconnect from Brent as well as barrels “pile up” on the coast."
As I have said in my newsletters and many of my podcasts, getting U.S. production back to where it was in mid-2014 was the easy part because the infrastructure existed already. U.S. liquids production hitting the lofty EIA projections is the hard part. Too much "Ultra Light" oil is another problem. - Dan
(ourselves included) thought the days of “blowout” price differentials between WTI and Brent were gone for good. Simply put, if the
arb opened up between U.S. and international pricing, more crude would be exported from the U.S. to fill the gap. Indeed, growing
U.S. crude exports have and will continue to be a major theme for the domestic and global energy markets. Unfortunately, these
pipeline bottlenecks between producing regions and export points (described above) have complicated the problem. Furthermore,
even if the pipes to the Gulf Coast were sufficient, the pace of rising U.S. supplies could possibly even exceed the capacity of crude
exports points to load it onto ships. Given that U.S. refiners are essentially maxed out on light sweet crude runs, essentially every
incremental barrel produced in the U.S from this point on will require waterborne exports. That means the U.S. will need a lot more
oil tanker loading capacity (and associated storage tanks) built along the Gulf Coast to meet this rising need for exports. This
developing need is not unknown and operators have already been rushing to expand export capacity out of the Gulf Coast. Recently
we reached a weekly high export number of ~2.6 million bpd, and by our estimates/best-guesses, current “max” capacity is somewhere
north of 3 million bpd and rising. However, a “maximum” level is not as simple as how fast we can technically load ships – as logistics
and shipping constraints likely make it difficult to maintain this level for an extended period. Keep in mind, crude oil is not the only
hydrocarbons we’re looking to export – as we continue to ramp exports of refined products, NGL’s, LNG, and petrochemicals, driving
even more competition for Gulf Coast dock space and logistics capacity. For now, we still think U.S. export capabilities should keep
pace with the flood of new U.S. light oil production that will need to be exported. That said, we are watching for the potential of an
emerging Gulf Coast export bottleneck which could show up if meaningful rail or pipe volumes out of the Permian occur earlier than
expected. In this scenario, we expect the Brent-WTI spread to remain wide, with the only difference being that coastal prices (MEH,
LLS) would also disconnect from Brent as well as barrels “pile up” on the coast."
As I have said in my newsletters and many of my podcasts, getting U.S. production back to where it was in mid-2014 was the easy part because the infrastructure existed already. U.S. liquids production hitting the lofty EIA projections is the hard part. Too much "Ultra Light" oil is another problem. - Dan
Dan Steffens
Energy Prospectus Group
Energy Prospectus Group
Re: Oil Price Forecast from RJ on June 4
READ THIS CAREFULLY. COMMENTS BELOW ARE FROM THE RAYMOND JAMES ENERGY STAT FOR JUNE 4, 2018.
Will wider Permian differentials drive meaningfully lower Permian operator cash flows and activity? Intuitively most investors
look at the huge differentials on their price screens and naturally think there is a direct relationship to Permian E&P cash flows.
Reality is somewhat different than the view from a Wall Street cubicle. There are several reasons why Permian cash flows and
resulting oilfield activity will not likely be as ugly as the screen prices might suggest including:
1. Many of the Permian E&P’s hedged basis differentials (we estimate this to be about 15%-20% of Permian operators),
2. Many Permian E&P’s also have firm, fixed pipeline transport capacity at relatively low prices (at $3-$4 /bbl to the coast). If
that capacity is directly to the Gulf Coast, these Permian producers are currently getting Brent minus only a few bucks (or
low $70/bbl) vs the mid $50/bbl price currently indicated by Permian spot prices (we estimate that 30% to 35% have these),
3. Even the guys that are not hedged and have no pipeline contracts (these are typically the smaller, non-public E&P’s) are
selling at Brent minus $20 to $25, so they are still getting around ~$55/bbl. Since their budgets were probably based upon
$50-$55/bbl cash flows are still higher than the budgets but do not afford meaningful growth, and finally
4. Since the Permian development has become more of a “manufacturing” process designed to optimized well completion
speed and lower overall well costs, any decision to actually reduce activity and disrupt the manufacturing process for a
relatively short-term price dislocation is not likely to happen on a widespread basis.
The bottom line is that we now believe Permian activity will stagnate in the back half of 2018, dip slightly in early 2019 and then
rebound steadily through the rest of 2019.
Will Permian operators be forced to “shut-in” production given the lack of pipeline takeaway? As detailed above, we believe the
Permian supply growth will exceed pipeline takeaway capacity by around 200,000 bpd over the next eighteen months. While
Cushing oil storage capacity will buffer some of this excess (through rising Cushing inventories) operators without contracted
pipeline capacity will be forced to either shut-in, slow activity, or find some other (more expensive) method of transport.
Historically, the price needed to actually force producers to shut in producing wells is much, much, lower than the spreads that we
are forecasting. Put another way, if producers are actually forced to shut in, the spot price differential could surge to $40 - $50/bbl
and realized spot Permian oil prices would fall to only $30/bbl.
In our view, shut-ins and a total Permian oil price collapse is not
likely since the most likely solution to the current bottlenecks includes some portion of increased rail shipments, some modest
activity deferrals starting in late 2018, with the balance coming from trucking shipments (which is constrained itself due to driver
shortages).
If rail shipments are able to ramp enough to satisfy the marginal barrel (unlikely) excess, differentials are likely to be
lower than we expect, and production continues to grow unimpeded at the strong rate we’ve previously expected. However, if rail is
unable to step in – or we see any hiccup (e.g., refiner outage, pipeline disruption) – producers may be faced by a physical (rather
than price) constraint on production growth as there is not ample storage in the basin and thus incremental barrels would need to
be trucked ever-longer distances in an extremely tight trucking market. This would force costs much higher and realized Permian oil
prices much lower (and possibly even leading some marginal producers to not receive service at all). In these extreme cases, the
most likely outcome would temper and/or defer completion activity for a brief period of time, awaiting both new takeaway and
higher prices.
An important point to keep in mind is that any level of reduced production volume from the Permian is essentially
removing additional barrels that are both expected and needed from an already tight global oil market. This would have the effect
of driving global oil prices (think Brent prices) materially higher. Layer in dramatic declines in Venezuela and potential impact from
the resumption of U.S. sanctions on Iran and Brent prices could move even higher if the Permian cannot get its oil to the coast.
Will wider Permian differentials drive meaningfully lower Permian operator cash flows and activity? Intuitively most investors
look at the huge differentials on their price screens and naturally think there is a direct relationship to Permian E&P cash flows.
Reality is somewhat different than the view from a Wall Street cubicle. There are several reasons why Permian cash flows and
resulting oilfield activity will not likely be as ugly as the screen prices might suggest including:
1. Many of the Permian E&P’s hedged basis differentials (we estimate this to be about 15%-20% of Permian operators),
2. Many Permian E&P’s also have firm, fixed pipeline transport capacity at relatively low prices (at $3-$4 /bbl to the coast). If
that capacity is directly to the Gulf Coast, these Permian producers are currently getting Brent minus only a few bucks (or
low $70/bbl) vs the mid $50/bbl price currently indicated by Permian spot prices (we estimate that 30% to 35% have these),
3. Even the guys that are not hedged and have no pipeline contracts (these are typically the smaller, non-public E&P’s) are
selling at Brent minus $20 to $25, so they are still getting around ~$55/bbl. Since their budgets were probably based upon
$50-$55/bbl cash flows are still higher than the budgets but do not afford meaningful growth, and finally
4. Since the Permian development has become more of a “manufacturing” process designed to optimized well completion
speed and lower overall well costs, any decision to actually reduce activity and disrupt the manufacturing process for a
relatively short-term price dislocation is not likely to happen on a widespread basis.
The bottom line is that we now believe Permian activity will stagnate in the back half of 2018, dip slightly in early 2019 and then
rebound steadily through the rest of 2019.
Will Permian operators be forced to “shut-in” production given the lack of pipeline takeaway? As detailed above, we believe the
Permian supply growth will exceed pipeline takeaway capacity by around 200,000 bpd over the next eighteen months. While
Cushing oil storage capacity will buffer some of this excess (through rising Cushing inventories) operators without contracted
pipeline capacity will be forced to either shut-in, slow activity, or find some other (more expensive) method of transport.
Historically, the price needed to actually force producers to shut in producing wells is much, much, lower than the spreads that we
are forecasting. Put another way, if producers are actually forced to shut in, the spot price differential could surge to $40 - $50/bbl
and realized spot Permian oil prices would fall to only $30/bbl.
In our view, shut-ins and a total Permian oil price collapse is not
likely since the most likely solution to the current bottlenecks includes some portion of increased rail shipments, some modest
activity deferrals starting in late 2018, with the balance coming from trucking shipments (which is constrained itself due to driver
shortages).
If rail shipments are able to ramp enough to satisfy the marginal barrel (unlikely) excess, differentials are likely to be
lower than we expect, and production continues to grow unimpeded at the strong rate we’ve previously expected. However, if rail is
unable to step in – or we see any hiccup (e.g., refiner outage, pipeline disruption) – producers may be faced by a physical (rather
than price) constraint on production growth as there is not ample storage in the basin and thus incremental barrels would need to
be trucked ever-longer distances in an extremely tight trucking market. This would force costs much higher and realized Permian oil
prices much lower (and possibly even leading some marginal producers to not receive service at all). In these extreme cases, the
most likely outcome would temper and/or defer completion activity for a brief period of time, awaiting both new takeaway and
higher prices.
An important point to keep in mind is that any level of reduced production volume from the Permian is essentially
removing additional barrels that are both expected and needed from an already tight global oil market. This would have the effect
of driving global oil prices (think Brent prices) materially higher. Layer in dramatic declines in Venezuela and potential impact from
the resumption of U.S. sanctions on Iran and Brent prices could move even higher if the Permian cannot get its oil to the coast.
Dan Steffens
Energy Prospectus Group
Energy Prospectus Group
Re: Oil Price Forecast from RJ on June 4
Who are the winners and losers in a wider Brent-WTI environment? Simply put, we think U.S. refiners win big with lower input
costs, U.S, Midstream wins with more demand for pipe, OPEC, international produces, and offshore service companies win with
higher Brent pricing, and finally rail and trucking wins with more demand for their services. On the losing side, the relatively small
number of Permian E&P’s that don’t receive near Gulf Coast or international pricing are relative losers and oilfield services may not
see as much growth as they would with all E&P’s getting near Brent pricing. This is similar to what we highlighted in our Permian
Stat several weeks ago, as from a broad perspective the winners from wider differentials are the midstream operators who have
exposure to basis differentials and refiners with the ability to run discounted crude grades, while the losers would be producers who
are exposed to discounted prices. However, as we’ve commented in the past (and plan to follow up on next week), many of the
E&Ps we cover have firm transportation agreements and/or hedges in place, so on the margin, while a wider Brent-WTI spread is
certainly a headwind for the group as a whole, many companies remain well positioned – particularly for the long-run. Additionally,
we note that absolute WTI prices at least need to be in the $50-60+/Bbl range in order to incentivize the level of production growth
needed to drive takeaway constraints. On the refining side, the group as a whole benefits from cheaper relative domestic crude
prices and we would highlight Strong Buy-rated Delek (DK) as the most weighted to Permian discounts, while HollyFrontier (HFC) is
another name with outsized leverage to broader inland differentials.
Conclusion: Get ready for “wider for longer” U.S. crude oil differentials as bottlenecks remain through 2019. As a follow-up to our
Permian oil price basis differential stat from a few weeks ago, in today’s Stat we detail why we expect the Brent-WTI differential to
widen and remain wider than our prior expectations for at least the next ~12-18 months. Specifically, we are raising our Brent and
lowering our WTI crude price forecast to accommodate a wider than expected $15/Bbl Brent-WTI spread through the end of 2019.
Specifically, we are raising 2019 Brent prices $5/Bbl to $80 higher and lowering our 2019 WTI estimate $5/Bbl to $65/bbl. Indeed,
while we envision new Permian pipelines allowing enough barrels to access the export markets through the Gulf Coast, we do not
expect any of these projects coming online until at least late 2019, meaning the dynamic depicted in today’s Stat, which has material
implications for nearly every company under our coverage, is set to govern the market for the medium term.
Furthermore, these widening oil price differentials between the mid-continent U.S. and Brent will result in many energy investing
nuances that will create varying winners and losers within each sub segment. Remember that just because the price on your screen
has changed due to limited pipeline capacity, the actual price realized by various E&P’s will be all over the board. From a big picture
perspective, we expect there will be winners and losers including: U.S. refiners win big with lower input costs; U.S. Midstream wins
with more demand for pipeline takeaway capacity; OPEC, international produces, and offshore service companies win with higher
Brent pricing; and finally rail and trucking wins with more demand for their services. On the losing side, the relatively small number
of Permian E&P’s that don’t receive near Gulf Coast pricing are relative losers and oilfield services may not see as much growth as
they would with all E&P’s getting near Brent pricing.
----------------------------------------
MY TAKE: Like all "FEARs", the Wall Street Gang will assume that all of the Permian Basin companies are going to be hurt equally by this situation. THAT IS NOT THE CASE. The larger public upstream companies, like those in our Sweet 16, saw this coming a year ago. They have good marketing departments and firm takeaway capacity contracted for a high percentage of their oil. Obviously, each company will need to address this issue in up-coming operational reports. - Dan Steffens
costs, U.S, Midstream wins with more demand for pipe, OPEC, international produces, and offshore service companies win with
higher Brent pricing, and finally rail and trucking wins with more demand for their services. On the losing side, the relatively small
number of Permian E&P’s that don’t receive near Gulf Coast or international pricing are relative losers and oilfield services may not
see as much growth as they would with all E&P’s getting near Brent pricing. This is similar to what we highlighted in our Permian
Stat several weeks ago, as from a broad perspective the winners from wider differentials are the midstream operators who have
exposure to basis differentials and refiners with the ability to run discounted crude grades, while the losers would be producers who
are exposed to discounted prices. However, as we’ve commented in the past (and plan to follow up on next week), many of the
E&Ps we cover have firm transportation agreements and/or hedges in place, so on the margin, while a wider Brent-WTI spread is
certainly a headwind for the group as a whole, many companies remain well positioned – particularly for the long-run. Additionally,
we note that absolute WTI prices at least need to be in the $50-60+/Bbl range in order to incentivize the level of production growth
needed to drive takeaway constraints. On the refining side, the group as a whole benefits from cheaper relative domestic crude
prices and we would highlight Strong Buy-rated Delek (DK) as the most weighted to Permian discounts, while HollyFrontier (HFC) is
another name with outsized leverage to broader inland differentials.
Conclusion: Get ready for “wider for longer” U.S. crude oil differentials as bottlenecks remain through 2019. As a follow-up to our
Permian oil price basis differential stat from a few weeks ago, in today’s Stat we detail why we expect the Brent-WTI differential to
widen and remain wider than our prior expectations for at least the next ~12-18 months. Specifically, we are raising our Brent and
lowering our WTI crude price forecast to accommodate a wider than expected $15/Bbl Brent-WTI spread through the end of 2019.
Specifically, we are raising 2019 Brent prices $5/Bbl to $80 higher and lowering our 2019 WTI estimate $5/Bbl to $65/bbl. Indeed,
while we envision new Permian pipelines allowing enough barrels to access the export markets through the Gulf Coast, we do not
expect any of these projects coming online until at least late 2019, meaning the dynamic depicted in today’s Stat, which has material
implications for nearly every company under our coverage, is set to govern the market for the medium term.
Furthermore, these widening oil price differentials between the mid-continent U.S. and Brent will result in many energy investing
nuances that will create varying winners and losers within each sub segment. Remember that just because the price on your screen
has changed due to limited pipeline capacity, the actual price realized by various E&P’s will be all over the board. From a big picture
perspective, we expect there will be winners and losers including: U.S. refiners win big with lower input costs; U.S. Midstream wins
with more demand for pipeline takeaway capacity; OPEC, international produces, and offshore service companies win with higher
Brent pricing; and finally rail and trucking wins with more demand for their services. On the losing side, the relatively small number
of Permian E&P’s that don’t receive near Gulf Coast pricing are relative losers and oilfield services may not see as much growth as
they would with all E&P’s getting near Brent pricing.
----------------------------------------
MY TAKE: Like all "FEARs", the Wall Street Gang will assume that all of the Permian Basin companies are going to be hurt equally by this situation. THAT IS NOT THE CASE. The larger public upstream companies, like those in our Sweet 16, saw this coming a year ago. They have good marketing departments and firm takeaway capacity contracted for a high percentage of their oil. Obviously, each company will need to address this issue in up-coming operational reports. - Dan Steffens
Dan Steffens
Energy Prospectus Group
Energy Prospectus Group
Re: Oil Price Forecast from RJ on June 4
Comments below from TPH
While Permian takeaway constraints have captured market attention in recent weeks, there may be another bottleneck on the horizon. Ramping Permian production has largely filled Cushing-bound Permian pipes PAA/Basin and OXY/Centurion, shifting the takeaway bottleneck to Cushing. Primary outlets to the Gulf Coast, ENB/Seaway and TRP/Marketlink, look to be highly utilized while 200mbpd East-bound refinery connection PAA/Diamond likely flowing near full. Outbound shipments to the Midwest are likely to ramp in the short-term as MPLX expands Ozark to 345mpbd from 230mbpd, although we would expect that spare capacity on BP/BP1 remains unused given the Whiting refinery shift to a heavier crude slate several years ago. In the near term, inbound volumes will continue to build as incremental DJ and Mid-Con barrels and Q1'19 120mbpd PAA/Sunrise Extension flow directly to Cushing storage. Tightening outbound capacity manifested in the physical market as Brent-WTI spreads have widened out to nearly ~$10/bbl -- well above multi-year norms. Bottleneck unlikely to see material improvement until Q4'19/Q1'20 in-service of ~2.4mbpd Permian to Gulf Coast long-haul capacity which will strip spot barrels off Cushing bound Permian pipes.
Client incoming calls on Friday held more questions around why Permian equities sold off vs. answers as to why they should. Our view remains that the broader Permian universe is unlikely to find a floor until realizations start to find a bottom. We remain firm in our belief that this will likely occur as pipelines fill completely (TPHe 2H'18) and basis widens enough to push in-basin realizations toward $45-50/bbl, causing operators to cut activity. Equities which were down 5-10% on Friday generally fit into the bucket of having a high degree of in-basin pricing exposure in 2019 including CPE, FANG, JAG, MTDR, SM, and XEC, while stocks that held up relatively well like OXY, WPX, and PXD have strong marketing positions. Near term we remain most constructive on APC, DVN, OXY, PXD, and WPX when owning names with Permian exposure.
While Permian takeaway constraints have captured market attention in recent weeks, there may be another bottleneck on the horizon. Ramping Permian production has largely filled Cushing-bound Permian pipes PAA/Basin and OXY/Centurion, shifting the takeaway bottleneck to Cushing. Primary outlets to the Gulf Coast, ENB/Seaway and TRP/Marketlink, look to be highly utilized while 200mbpd East-bound refinery connection PAA/Diamond likely flowing near full. Outbound shipments to the Midwest are likely to ramp in the short-term as MPLX expands Ozark to 345mpbd from 230mbpd, although we would expect that spare capacity on BP/BP1 remains unused given the Whiting refinery shift to a heavier crude slate several years ago. In the near term, inbound volumes will continue to build as incremental DJ and Mid-Con barrels and Q1'19 120mbpd PAA/Sunrise Extension flow directly to Cushing storage. Tightening outbound capacity manifested in the physical market as Brent-WTI spreads have widened out to nearly ~$10/bbl -- well above multi-year norms. Bottleneck unlikely to see material improvement until Q4'19/Q1'20 in-service of ~2.4mbpd Permian to Gulf Coast long-haul capacity which will strip spot barrels off Cushing bound Permian pipes.
Client incoming calls on Friday held more questions around why Permian equities sold off vs. answers as to why they should. Our view remains that the broader Permian universe is unlikely to find a floor until realizations start to find a bottom. We remain firm in our belief that this will likely occur as pipelines fill completely (TPHe 2H'18) and basis widens enough to push in-basin realizations toward $45-50/bbl, causing operators to cut activity. Equities which were down 5-10% on Friday generally fit into the bucket of having a high degree of in-basin pricing exposure in 2019 including CPE, FANG, JAG, MTDR, SM, and XEC, while stocks that held up relatively well like OXY, WPX, and PXD have strong marketing positions. Near term we remain most constructive on APC, DVN, OXY, PXD, and WPX when owning names with Permian exposure.
Dan Steffens
Energy Prospectus Group
Energy Prospectus Group
Re: Oil Price Forecast from RJ on June 4
More from TPH
As previously highlighted, tightening Cushing outbound capacity presents slew of opportunities and challenges for upstream and midstream operators alike. As incremental Permian, DJ and Mid-Con barrels are directed to Cushing, growing demand for terminal capacity to benefit storage heavy-weights PAA, ENB, MMP and SEMG. Deteriorating WTI pricing may need to incentivize marginal Bakken and PRB barrels to eschew Cushing-bound TEP/PXP for alternatives that circumvent Cushing bottleneck, principally ETP/Dakota Access and rail. Widening WTI differential likely pressures recontracting outlook for legacy TEP/Pony Express and SEMG/White Cliffs contracts set to roll 2H'19 given connection to a disadvantaged Cushing market. Further downstream, benefit accrues to crude export incumbents OXY, EPD and MMP as marginal U.S. barrels find their way to the water given growing global appetite for lighter U.S. barrels.
As previously highlighted, tightening Cushing outbound capacity presents slew of opportunities and challenges for upstream and midstream operators alike. As incremental Permian, DJ and Mid-Con barrels are directed to Cushing, growing demand for terminal capacity to benefit storage heavy-weights PAA, ENB, MMP and SEMG. Deteriorating WTI pricing may need to incentivize marginal Bakken and PRB barrels to eschew Cushing-bound TEP/PXP for alternatives that circumvent Cushing bottleneck, principally ETP/Dakota Access and rail. Widening WTI differential likely pressures recontracting outlook for legacy TEP/Pony Express and SEMG/White Cliffs contracts set to roll 2H'19 given connection to a disadvantaged Cushing market. Further downstream, benefit accrues to crude export incumbents OXY, EPD and MMP as marginal U.S. barrels find their way to the water given growing global appetite for lighter U.S. barrels.
Dan Steffens
Energy Prospectus Group
Energy Prospectus Group