ne market dynamics - s&p global platts...2013 2015 2017 2019 2021 2023 cf) us demand and exports...

NE Market Dynamics:

Perspectives and Challenges

S&P Global Platts Analytics

Richard Redash – Head of Global Gas Planning

June 2019

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Perceptions of abundant low-cost US gas supply partly behind extended NYMEX futures downtrend — from ~$5 to ~$3/MMBtu

$0

$1

$2

$3

$4

$5

$6

2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031

$/M

MB

tu

2014 2015 2016 2017 2018 2019

Source: CME NYMEX and Platts Analytics

NYMEX Calendar Strip Prices as of early January

2


Midstream

Midstream constraints shift traditional balancing point toward supply; limiting downstream influx and impact on Henry Hub

Demand Supply

Pipe DelaysHenry Hub now a

premium priced

demand hub

Upstream (and some

key downstream)

prices at risk to

greater basis

weakness/volatility

3

Source: Platts Analytics


Henry Hub Bubble: pipeline capacity needed to support US gas supply gains — raising risk of more gas-on-gas competition

Key Basins

Wet Gas

Dry Gas

4Source: Platts Analytics


US Demand gains from power and industrial sectors in shale era far from diffuse – less than a dozen grew by 0.5 Bcf/d, or more

(0.8)

(0.6)

(0.4)

(0.2)

-

0.2

0.4

0.6

0.8

1.0

1.2

1.4

1.6

1.8

2.0

CA

ME

NH

CO

OR

AZ

MA RI

VT

MT

NE

WA

UT

WV

SD

WY ID ND

KS

NM

MO

NV

NY

DE

OK

MN

MD

CT

AR

KY IL IA NJ

WI

TN

SC MI

MS

OH

GA IN VA

NC

AL

LA

PA

FL

TX

US Power + Industrial Demand Growth: 2018 vs 2008 (Bcf/d)

Power Industrial

20 states accounted for

14.6 Bcf/d (95%) of total

15.4 Bcf/d gain

5Source: EIA and Platts Analytics


Additional call on US supply gains — past performance is actually indicative of future demand

Growth

High

Low


US gas demand growth now largely dependent on exports — LNG and Mexico — NE a distant second!

-6

-4

-2

0

2

4

6

8

10

12

2013 2015 2017 2019 2021 2023

Bcf/

d (

Y/Y

ch

g.)

US Demand and Exports

Power + Industrial Exports (LNG + Mex) Total

7

4.0

2.4

18 vs 12 24 vs 18

-

2

4

6

8

10

12

Bc

f/d

(Y

/Y c

hg

.)

Demand (including Exports) by Cell Region

NE TX/SE Midcon West

Source: N.A. Gas Five-Year Forecast quarterly report


Gulf LNG bias ‘inflates’ Henry Hub bubble; raises allure of West Coast returns for next wave of North American LNG exports

Gulf Coast Advantages:

• Pipeline interconnectivity

• Existing industrial sites

• Skilled workforce

• Near Henry Hub

East Coast Advantage:

• Shipping costs to Europe

West Coast Advantage:

• Shipping cost to Asia

• Supply gas discounts

• Avoid Panama Canal

• Lower trade riskSource: Global LNG

8


Concentration of demand growth along Texas/Louisiana coast supportive adds to infrastructure challenge NE production faces

9

-0.50.00.51.01.52.0

19 20 21 22 23 24-0.50.00.51.01.52.0

19 20 21 22 23 24

-0.50.00.51.01.52.0

19 20 21 22 23 24

-0.50.00.51.01.52.0

19 20 21 22 23 24

-0.50.00.51.01.52.0

19 20 21 22 23 24

-0.50.00.51.01.52.0

19 20 21 22 23 24

-0.50.00.51.01.52.0

19 20 21 22 23 24

Source: N.A. Gas Five-Year Forecast quarterly report

Bcf/d


Infrastructure buildout peaked in 2018, new project docket dwindles beyond 2019 Infrastructure trends

Infrastructure buildout slowdown

0

1

2

3

4

5

6

7

8

9

2015 2016 2017 2018 2019 2020 2021 2022

Bc

f/d

Production-takeaway capacity additions

10

• Large production-takeaway projects proposed in 2014-2016 are all (mostly) in service

• Slowdown in project applications, “saturated” capacity market point to increasingly less takeaway capacity coming online over next few years

• Narrow hub differentials make new project economics challenging

• Producers likely have little appetite for more costly reservation charges when in-basin pricing is now competitive


Northeast projects entering service in 2018 and beyond largely don’t connect with highest demand-growth regions

11

Source: S&P Global Platts

Expansion capacity by downstream destination

3.95

Bcf/d

4.0

Bcf/d

4.85

Bcf/d

4.26

Bcf/d

Northeast

Mid-Atlantic

Southeast

Midcon Market/East

Canada


Northeast expansion projects by downstream delivery region (Bcf/d)

Major production takeaway projects and direct-to-Southeast capacity

The “last mile problem”— most Northeast expansion projects don’t connect supply with demand (directly)

- 1 2 3 4

Atlantic Sunrise

PennEast

Rover Pipeline

NEXUS

Mountain Valley

Atlantic Coast

Mountaineer XPress

Leach XPress

WB XPress

Southeast Capacity Non-Southeast Capacity

12

Project Name

Capacity

(Bcf/d) Receipt Area Delivery Area

Direct Southeast

Capacity (Bcf/d)

Atlantic Sunrise 1.70 NE App.

Mid-Atlantic,

Southeast 0.85

PennEast 1.10 NE App. Mid-Atlantic -

Rover Pipeline 3.25 SW App.

Midwest,

Southeast 0.75

NEXUS Gas

Transmission 1.50 SW App. Midwest -

Mountain Valley

Pipeline 2.00 SW App. Mid-Atlantic -

Atlantic Coast

Pipeline 1.50 SW App. Mid-Atlantic -

Mountaineer

XPress 2.70 SW App.

TCO Pool,

Southeast 0.80

Leach XPress 1.50 SW App.

TCO Pool,

Southeast 1.00

WB XPress 1.30 SW App.

TCO Pool,

Southeast 0.20

Southeastern

Trail 0.30 Mid-Atlantic Southeast 0.30

16.85 3.90

Source: S&P Global Platts


20

22

24

26

28

30

32

34

Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec

Bcf/

d

Northeast Dry Gas Production

2016 2017 2018 2019

NE production growth has already stalled, but for how long?

13

Source: Daily Supply/Demand Analytic Report


Free cash flow focus drives drilling and completion budgets lower

Growth Historically Funded Through

Equity, Debt and Asset Sales

Producer sample explains ~70% of

basin growth

$(6)

$(5)

$(4)

$(3)

$(2)

$(1)

$-

2014 2015 2016 2017 2018

$ (

Bil

lio

ns

)

Upstream Op. Cash Flow - D&C Capex

0

2

4

6

8

10

12

14

16

2014 2015 2016 2017 2018

Bc

f/d

Sample includes: AR, SWN, RRC, CNX, COG, GPOR, EQT/RICE & Ascent

14


Key Operator Guidance Suggests Slowing Growth

Net Appalachian

Production (Bcf/d) 4Q2018 FY 2019

Antero 2.1 2.3

Southwestern 1.6 1.5

EQT 4.0 3.8

Range 1.3 1.4

Cabot 2.2 2.4

Gulfport 1.1 1.1

CNX 1.4 1.3

Ascent 1.7 1.9

Total 15.4 15.7

$2,255 $1,600

$695

$538

$836

$685

$1,400

$1,175

$894

$800

$607

$600

$870

$880

$906

$1,000

$-

$1,000

$2,000

$3,000

$4,000

$5,000

$6,000

$7,000

$8,000

$9,000

2018 2019

Mil

lio

n D

oll

ars

Ascent

SWN

CNX

COG

AR

RRC

GPOR

EQT

Drilling & Completion Budgets Down

12% Lower Y/Y

15


Northeast supply cash basis has improved due to de-bottlenecked constraints Rationale?

Northeast prices

(3.0)

(2.5)

(2.0)

(1.5)

(1.0)

(0.5)

-

0.5

Ja

n-1

7

Ma

r-1

7

Ma

y-1

7

Ju

l-1

7

Sep

-17

No

v-1

7

Ja

n-1

8

Ma

r-1

8

Ma

y-1

8

Ju

l-1

8

Se

p-1

8

No

v-1

8

Ja

n-1

9

Ma

r-1

9

$/M

MB

tu

Dominion TETCO M2 Transco Leidy

16

• Are deep basis discounts a thing of the past?

• Surge in production-takeaway capacity installations has largely de-bottlenecked previously constrained outflow corridors

• As production grows and pipeline capacity growth stalls, a return to basis discounts may be an inevitability

• Market has not priced-in the possibility of future capacity constraints, and forward curve does not incentivize new pipeline construction at this stage


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ne market dynamics - s&p global platts...2013 2015 2017 2019 2021 2023 cf) us demand and exports...

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