permian basin natural gas prices– how low can they go?...average permian production for march...
TRANSCRIPT
Pressured by a convergence of market conditions, natural gas prices in the Permian basin have reached
unprecedented, historic lows. With increased oil production in the region came a corresponding
increase in associated gas production. Over the past month, gas volumes bumped into takeaway
capacity ceilings due to a combination of short-term and long-term infrastructure constraints. This
unprecedented price environment could remain in place for the next several months depending on
when new takeaway capacity becomes available with infrastructure additions.
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ANALYST INSIGHT SERIESGAS
Permian Basin Natural Gas Prices– How Low Can They Go? Joseph Bernardi, Natural Gas Analyst II | Anne Keller, Product Director, NGLs | Mark Chung, NGL Products Analyst
APRIL 2019
Overview of Price Movements and Production Background
Before March 2019, no U.S. natural gas
trading hub ever averaged a negative cash
price. Beginning the week of March 18, spot
cash prices in the Permian fell heavily into
negative territory and remained suppressed
for an unprecedented amount of time. For
example, average cash price at the Waha hub
fell as low as negative $5.75 and averaged in
the negatives for two consecutive weeks of
trading. Its lowest trade during that time was
negative $9, a new record low for any natural
gas hub in North America according to NGI
data. In comparison, Waha averaged a spot
cash price of positive $1.74 in the first two
months of 2019. Permian hubs in addition
to Waha – such as El Paso Permian and
Transwestern – moved similarly into completely
uncharted territory.
The price cratering occurred in conjunction
with a notable uptick in gas production, already
at record high levels according to Genscape’s
Natural Gas Daily Production data. The same
was true for each of the previous three months,
through December 2018; moreover, 15 of
the previous 18 months showed month/month increases in Permian production. The second half of March 2019
contributed the lion’s share of that month’s growth. Average Permian production for March 16-31 was about 10.4
Bcf/d, an increase of about 250 MMcf/d compared to the February average, and of nearly 500 MMcf/d compared
to the average for March 1-15. For reference, March 2019’s production was about 1.85 Bcf/d above the March
Permian Basin Natural Gas Prices– How Low Can they Go?
Waha Cash Prices, 1/1/2019-4/15/2019
$(10.00)
$(8.00)
$(6.00)
$(4.00)
$(2.00)
$-
$2.00
$4.00
$6.00
1/2/19 1/9/19 1/16/19 1/23/19 1/30/19 2/6/19 2/13/19 2/20/19 2/27/19 3/6/19 3/13/19 3/20/19 3/27/19 4/3/19 4/10/19
$US/
MM
Btu
Low Average High
Permian Production Since 2016
-
2,000
4,000
6,000
8,000
10,000
12,000
12/1/
161/1
/172/1
/173/1
/174/1
/175/1
/176/1
/177/1
/178/1
/179/1
/17
10/1/
17
11/1/
17
12/1/
171/1
/182/1
/183/1
/184/1
/185/1
/186/1
/187/1
/188/1
/189/1
/18
10/1/
18
11/1/
18
12/1/
181/1
/192/1
/193/1
/194/1
/19
MM
cf/d
2ANALYST INSIGHT SERIES APRIL 2019
ANALYST INSIGHT SERIES
2018 average, and about 3.6 Bcf/d above the March 2017 average. Permian gas volumes reached about 10.8
Bcf/d for the first time ever in March 2019, just before the biggest cratering in spot cash prices occurred.
Background: Infrastructure
Continual production growth outstripped takeaway capacity additions from the Permian. For example, despite
an increase of about 1.4 Bcf/d in average monthly production from July 2018 to January 2019, incremental
infrastructure takeaway capacity tallied less than 700 MMcf/d. The El Paso Natural Gas (EPNG) system added
about 180 MMcf/d of new capacity north out of the Permian in early December and flows at the corresponding
“PERMPLNS” meter immediately jumped up to the new increased capacity. ONEOK’s WesTex Expansion II, which
started in December, increased capacity to move Permian gas to the Texas Panhandle by 150 MMcf/d.
On the intrastate side, Energy Transfer’s
North Texas Pipeline completed an
expansion, adding about 160 MMcf/d
eastbound through compression
upgrades. The incremental gas was
earmarked to flow through the recently
revitalized Old Ocean system, which
connects the North Texas system to the
Katy market area along the Gulf Coast.
Permian-to-Mexico flows have also
increased in 2019, due to new
connections to the gas grid in western
Mexican markets and the displacement of
traditional sources of Mexican supply in
northern Mexico.
Recent Takeaway Issues Due to Maintenance
In addition to the longer-term existing infrastructure constraints, there were also acute, unplanned maintenance
events on multiple systems corresponding to the Permian’s substantial price drops.
EPNG experienced Force Majeure equipment failures at its Lordsburg and Florida Compressor Stations in
southern New Mexico beginning on March 19, two days before Waha’s first trade date with a negative cash
average. This work resulted in an operational capacity reduction, and corresponding flow reduction, of about
200 MMcf/d at the “L2000” flow meter in west Texas, per Genscape’s Natural Gas Basis Commentary. Flows
remained at this reduced level for 12 days, with an additional 4 days of a less restrictive flow limit before
returning to normal on April 4. When this meter was limited, Waha cash averaged negative $1.07; in the week
before and week after the flow limits, Waha cash averaged positive $0.61.
Permian Production and Modeled Flow Constraints Since April 2017
-
2,000
4,000
6,000
8,000
10,000
12,000
14,000
4/1/
175/
1/17
6/1/
177/
1/17
8/1/
179/
1/17
10/1
/17
11/1
/17
12/1
/17
1/1/
182/
1/18
3/1/
184/
1/18
5/1/
186/
1/18
7/1/
188/
1/18
9/1/
1810
/1/1
811
/1/1
812
/1/1
81/
1/19
2/1/
193/
1/19
4/1/
195/
1/19
6/1/
197/
1/19
8/1/
199/
1/19
10/1
/19
11/1
/19
12/1
/19
MM
cf/d
Permian Production Modeled Flow Constraints
3ANALYST INSIGHT SERIES APRIL 2019
A second Force Majeure on EPNG at its Caprock Station also limited Permian outflows to the north via the
“PERMPLNS” and “LINCOLN N” meters just as cash prices began to drop below zero. As tracked in Genscape’s
Notices & Maintenance, the second Force Majeure started in late December – only a few weeks after Permian North
expansion entered service. Then in March as cash prices started to dip into the negatives, the Force Majeure required
an additional, temporary reduction of ~150 MMcf/d.
Planned maintenance on Transwestern also reduced Permian outflow capacity starting around this time, as work on
their Compressor Station 8 in New Mexico limited westbound flows to 466 MMcf/d beginning on April 2. This limit,
which was in place for over two weeks, represented a decrease of 135 MMcf/d relative to year-to-date volumes.
Rumors of maintenance on the Oasis intrastate system were partially supported by data from interstate
pipelines. Oasis’s interconnects with EPNG and Northern Natural Gas (NNG) showed a notable flip around the
time that prices started to drop precipitously. These pipes delivered an average of about 85 MMcf/d to Oasis
in the previous 30 days but switched to receiving as much as ~300 MMcf/d when prices initially dipped into
negative territory. However, the interstates’ receipts only remained this high for several days and even reverted
to deliveries to Oasis while prices continued to freefall. This Oasis flip also occurred at the same time as the
onset of the EPNG Force Majeure.
Negative Prices – How? Considering Gas, Oil, and NGLs
How could spot natural gas prices go negative? And given that zero has not functioned as a boundary on how
low prices can go, might any such boundary exist? To understand these unprecedented gas prices, we need to
consider gas within a broader context of hydrocarbon commodities in the basin.
A significant portion of the Permian’s gas production is classified as associated gas, meaning that the focus of
drilling activity in the basin is based on oil economics. There is little incentive for producers to reduce drilling
to restrain gas production given that crude prices are roughly $60/bbl. As evidenced by recent activity, even
negative gas prices are not enough to stop production; this is largely due to revenues from the NGLs and higher-
chained hydrocarbons included within the gas stream making up for the negative value of gas molecules.
Recently expanded NGL extraction and pipeline takeaway capacity provide an outlet for these molecules if the
gas can be sent to a processing plant.
Given the ease with which Texas operators can flare, why would prices go negative at all? Another factor that may
have contributed to gas prices diving into negative territory is the addition of Whitewater Midstream’s Agua Blanca
intrastate line, which entered service April 2018. This line contractually committed volumes for transportation to
the Waha Hub from Permian gas processing plants. This was a notable change on several levels: not only did it
directly connect more plants to the hub, it also did so on a relatively inflexible basis, limiting the possibility of flaring
these molecules once past the plant tailgate.
According to Genscape’s Natural Gas Production Forecast, the average Permian well is a mixed hydrocarbon
stream, which on an MMBtu basis consists of around 61 percent crude oil, 12 percent NGLs, and 27 percent
methane. The gas-NGL mixture is separated from crude oil and sent to processing plants, where methane is
4ANALYST INSIGHT SERIES APRIL 2019
isolated from the other hydrocarbons.
Producers cannot selectively flare
methane at the wellhead – they
would have to flare the entire gas
stream, including NGLs, together.
Only after NGLs are extracted at the
processing plant can the now-dry
gas be flared on its own. Permian
processing plants are already
incentivized to flare essentially
as much methane as they can,
particularly with prices dipping into
negative territory, so the next place
where flaring could occur is in the
field. Until the value of the entire gas stream at the wellhead reaches zero, producers have an incentive to move
it if the gathering lines have capacity. How low would gas prices have to go to reduce the value of the entire gas
stream to zero? This number depends on NGL prices and on the ratio of dry gas to NGLs for a given well and is
thus a moving target which can vary with geography and time. For example, the value of a gas stream that is 71
percent methane and 29 percent NGLs would still be positive even at a negative $5/MMBtu Waha cash price. At
the same gas price, the value of a lighter stream (for example 80 percent methane and 20 percent NGLs) would
become slightly negative given current pricing for ethane, propane, and other NGLs.
Recent increases in NGL takeaway capacity and fractionation capacity alleviated previous constraints, according
to Genscape’s U.S. NGL Infrastructure Intelligence. This provides more capacity for ethane recovery, allowing
molecules that would otherwise be delivered into a gas line to be sold as NGL, as well as boosting throughput of
other NGL components.
Fractionation capacity does not appear to be a constraint for Permian producers in the immediate term, as two
new fractionators are coming: Energy Transfer’s 150 mb/d unit that started up in February and another at Targa
(100 mb/d) that is expected to start any day now.
For NGL takeaway, Enterprise’s Shin Oak NGL pipeline entered interim service in February. It has capacity to
move 250 mb/d from Orla to Mont Belvieu, of which about 115 mb/d is assumed to be new capacity. The
remainder represents volumes that were on Enterprise’s Seminole Red Line before its conversion in February to
crude service. In addition, Targa’s 300 mb/d Grand Prix line began limited operations last year and is assumed
to be able to receive NGLs, moving minimal volumes currently. Given their new fractionator just started service,
an additional 100 mb/d of incremental Y-grade can be handled at Mont Belvieu. The new capacity on Shin Oak
and Grand Prix can handle the output from both of Enterprise’s 300 MMcf/d gas processing trains at Orla and as
many as twelve, 200 MMcf/d processing plants on the Targa system.
Waha Daily Cash Price and Gas-NGL Stream Breakevens
-$8.00
-$6.00
-$4.00
-$2.00
$0.00
$2.00
$4.00
$6.00
1-Apr-
19
2-Apr-
19
3-Apr-
19
4-Apr-
19
5-Apr-
19
6-Apr-
19
7-Apr-
19
8-Apr-
19
9-Apr-
19
10-A
pr-19
11-A
pr-19
$US/
MM
Btu
WAHA Gas Rich Gas Margin Lean Gas Margin
5ANALYST INSIGHT SERIES APRIL 2019
On the ethane demand and pricing front, ethane prices remain at a level at the Mont Belvieu Hub that allows producers
to recover and sell ethane. This allows them to essentially get a Henry Hub plus price if they have access to transportation
and fractionation capacity for their NGLs. Gas prices in the Permian could continue to flirt with negative territory as long
as Mont Belvieu ethane is priced above the costs to transport ethane and fractionate it at Mont Belvieu – $0.10 per
gallon. Given that ethane can be regasified and sold in Houston at Ship Channel gas prices, this seems like a sure bet,
and likely to support higher throughput on NGL lines at least while the gas markets sort themselves out.
Negative Prices – How? Considering Historical Analogs
In addition to viewing these unprecedented gas prices in a broader multi-commodity scope, we can also
compare approximate historical analogs where takeaway constraints bottled up production and put considerable
downward pressure on prices.
Only two other hubs in North America outside of the Permian have ever traded into negative territory: Westcoast
Station 2 and AECO. Both are in western Canada, and market conditions that drove their historic moves share
some commonalities with the recent Permian price environment. As in the Permian, these western Canadian
markets experienced unplanned outages that cut into an already limited export capacity, constraining a significant
amount of production. Nearly all the daily average spot cash prices below zero at these hubs occurred after the
recent Force Majeure explosion in October 2018 on Enbridge’s Westcoast pipeline, which cut a significant amount
of flow capacity south out of British Columbia. The supply hub most significantly affected by this outage was
Westcoast Station 2, which averaged a negative cash price nine times in the two months following the explosion.
Western Canadian production averaged about 15.5 Bcf/d in the prior month but dropped by as much as 700
MMcf/d during that two-month period. The AECO hub in Alberta, which experienced weakened pricing in
2018 due to production growth and limits on provincial exports, was dragged down even further following the
Westcoast explosion. It averaged negative $0.01/MMBtu in mid-October 2018, the second time it reached this
mark. The first such date came in May 2018 amid weak shoulder-season demand and elevated production.
Recent Market Developments After Record-Setting Prices
Since the lowest marks were set for spot gas prices in the Permian, production decreased and cash prices
climbed back up mostly into positive territory.
Immediately after the two-week streak of negative marks, Waha cash returned above zero for most of the week
of April 8. It posted a weekly average of positive $0.35 that week, a notable increase from negative $5.75 levels,
but still well below previous norms such as the Jan-Feb average of $1.74 and the 2018 average of $1.98.
Overall production decreased noticeably in the first half of April, particularly compared to the record highs around
10.8 Bcf/d in late March discussed earlier. The period of April 1 through April 15 saw Permian production average just
9.76 Bcf/d, down 650 MMcf/d from late March’s average. If April’s volumes were to continue at their current level for
the rest of the month – which should not necessarily be assumed – it would represent the lowest monthly average for
Permian production since November 2018, and the largest month/month decrease for the region in over three years.
6ANALYST INSIGHT SERIES APRIL 2019
Permian flare counts increased with the negative pricing, as tracked in Genscape’s Natural Gas Daily Production
data. Using a rolling 10-day average to account for daily variations due to issues like cloud cover and new wells
coming online, flare counts show two notable increases. The first corresponds with the initial onset of negative
pricing and the second comes shortly after the lowest negative prices seen thus far.
With such steep declines in gas
prices and the contributions
from NGL prices discussed
above, producers would be
fundamentally incentivized to
first cut gas that has a lower
NGL content. Receipts onto
EPNG from Apache’s Alpine
High, an example of an area
with “leaner” hydrocarbon
stream, dropped off considerably
as spot cash prices approached
their nadir. These receipts also
posted a noteworthy increase
that corresponded with the first drops in prices. As of March 19, the year-to-date receipts onto EPNG from
Alpine High averaged 420 MMcf/d, with only two days during that period above 475 MMcf/d. Then beginning
on March 20, this location posted receipts in excess of 490 MMcf/d for eight straight days, averaging 533
MMcf/d during that time and reaching a maximum of 553 MMcf/d. Waha spot cash price first descended below
zero during this time, going as low as negative $1.95 on March 28, when Alpine High receipts also dropped
back below the year-to-date average. Since then, these receipts have remained abnormally low, averaging only
~300 MMcf/d and failing to exceed 400 MMcf/d. The difference between that peak at ~550 MMcf/d and the
recent average of ~300 MMcf/d closely aligns with Apache’s recently announced deferrals of ~250 MMcf/d of
production due to current Waha pricing.
Outlook for This Price Environment
Fundamentally, this pricing environment in the Permian should persist if production remains robust and
takeaway constraints remain in place. Futures prices for Permian natural gas hubs indicate market expectations
that this extraordinary price environment is far from over. The May 2019 contract at Waha fell into negative
cash territory at the beginning of April and essentially remained negative since. The June contract also slid
downwards over the last month but has thus far stayed above zero.
As detailed in our Permian Oil Analyst Insight Report, oil takeaway constraints in West Texas are somewhat
relieved by recent capacity additions, but the construction timeline of several more pipelines will determine
how much of a bottleneck remains for Permian oil in 2019. Based on the current outlook, though, Genscape’s
Alpine High Receipts and Waha Cash since 4/1/2018
$(8.00)
$(6.00)
$(4.00)
$(2.00)
$-
$2.00
$4.00
$6.00
-
100
200
300
400
500
600
4/1/18 5/1/18 6/1/18 7/1/18 8/1/18 9/1/18 10/1/18 11/1/18 12/1/18 1/1/19 2/1/19 3/1/19 4/1/19
Receipts Waha Average Cash Price Zero $/MMBtu
7ANALYST INSIGHT SERIES APRIL 2019
© Copyright 2019, Genscape Incorporated. All rights reserved.
Natural Gas Production Forecast shows gas production continuing to steadily increase quarter/quarter
throughout 2019 due to favorable oil economics. Intra-basin summer gas demand is growing year/year, which
may continue to help somewhat in bridging the gap between production growth and takeaway capacity.
However, increased demand alone should not be regarded as a savior for Permian gas constraints this summer.
On the U.S. side, the next major line that will facilitate Permian outflows is Kinder Morgan’s Gulf Coast Express
(GCX). This project is on schedule for an October 1 in-service date, per Genscape’s Infrastructure Intelligence
which conducted a reconnaissance flight over the pipeline in late March. In its Q1 2019 earnings call held April
17, Kinder Morgan’s CEO Steve Kean reiterated that Kinder Morgan was “going to do everything we can, to be
there for our customers just as fast as we can,” but also noted that they were “not comfortable in projecting
some kind of an early in-service date [for Gulf Coast Express] …other than the October 1st at this point.”
Infrastructure additions that would increase allowable gas outflow from the Permian could help to alleviate
the strong downward pressure on prices. We expect the first relief on the infrastructure front to come via new
pipelines in Mexico, according to Genscape’s Mexico Natural Gas Supply & Demand. The first notable Mexican
project will be the Samalayuca-Sasabe system, which we expect online sometime in August. While this project is
not expected to actually increase exports to Mexico, it is anticipated to help relieve Permian outbound capacity
on El Paso’s South Mainline. The next major Mexican project to come online will be the the Wahalajara system
around mid-December. Wahalajara projects will support significant increases of Permian outflows by enabling
molecules to reach central Mexican demand markets, where they can: displace a portion of the country’s
expensive LNG imports, offset domestic production declines, serve moderate demand growth, and displace
portions of U.S.-to-Mexico pipeline exports from other U.S. regions. Any delays to these Mexican pipes could
lead to sustained increases in Permian flares and continued downward pressure on area basis prices.
Conclusion
Natural gas prices in the Permian continue to print previously unheard-of low prices. Production shows strong
growth over the last several years, and gas molecules will remain mostly at the mercy of other commodities’
economics in the near term. With continued physical export limitations as well as any short-term acute
maintenance issues that may crop up, there is potential for this pricing situation to remain wild until the arrival
of new infrastructure additions to relieve existing bottlenecks. Genscape’s suite of natural gas, production, and
NGL products will remain crucial for monitoring further developments in the Permian.
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