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.

1

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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