clear as mud(rocks): a forward view of natural gas · annual reports; michot foss analysis...

©BEG/CEE-UT, 1

Clear as Mud(Rocks): A Forward View of Natural GasERCOT BOD April 10, 2018

Michelle Michot Foss, Ph.D., UT BEG/CEE

©BEG/CEE-UT, 2

Overview: U.S. and Texas Natural Gas Supply

• What a success story! The only considerations are…• …downward pressure on natural gas prices…

– How much? How long? With what consequences (more on that later)?

• …because of tight rock dynamics…– The “bidness” and how to think about it

• …and the need to re-plumb the gas system…– “Primer” on Texas/ERCOT gas infrastructure and flows

• …in an extended period of consumer sovereignty.– Plenty of ideas. Will they all work?

©BEG/CEE-UT, 3

$0$1$2$3$4$5$6$7$8$9

$10$11

"Moderate" HH Price Deck "High" HH Price Deck

Gas Price Economics (2030)

Annual average, real price; Michot Foss, OIES NG 18 (2007) and NG 58 (2011); www.oxfordenergy.org

Supp

ly M

ix

HH price dependent (**70-80%, “NAG”, dry; ~60% gas wells)

Oil price dependent (**20-30+%, “AG”, “wet”;

*Production (25-30+ TCF):

Price events below $3 can happen

NGLs, Condensate, “wet” gas(oil linked, S-D, export drivers)

Price events above $6 can happen

LNG In?S-D interactions relative to supply cost, deliverability

Total Methane Supply

* Canadian gas production, pipe delivery subject to same conditions; **EIA reserves reporting.

LNG Out?

http://www.oxfordenergy.org/

©BEG/CEE-UT, 4

Ever More Reliance on “Mud Rocks”

Offshore (Federal, State)

Onshore (Conventional)

CBM

Tight Rock (Shale)

-

5

10

15

20

25

30

35

Tilli

on C

ubic

Fee

t

Note: 2017 data are estimates

Of which (approx.):TX 28%PA, OH, WV 28%While:GOM OCS 1%

U.S. Energy Information Administration; Michot Foss analysis

©BEG/CEE-UT, 5

Ever More Reliance on Associated Gas

0

5

10

15

20

25

30

35

-

5

10

15

20

25

30

35

Trill

ion

Cubi

c Fe

et

Associated Gas Production

Nonassociated Gas Production

U.S. Natural Gas Total Consumption (MMcf)

Natural Gas Delivered to Consumers in the U.S. (MMcf)

Note: 2017 data are estimates


“Free” gas. Yay!Byproduct of• Hunt for liquids, especially

Permian black oil;• Over-pressured tight rock;• Enormous gas drive

“engines”.How much? How long?

©BEG/CEE-UT, 6

Oil, Liquids Drive DecisionsRelative to Opportunities

-

5

10

15

20

25

30

35

40

0%

10%

20%

30%

40%

50%

60%

70%

80%

90%

U.S. Natural Gas Gross Withdrawals from Oil Wells (MMcf)

U.S. Natural Gas Gross Withdrawals from Gas Wells (MMcf)

WTI:HH

Oil, Gas Prices in Rough Parity

Oil Premium


Gas Premium

0%

10%

20%

30%

40%

50%

60%

70%

80%

90%

100%

OilGas

Share of rigs drilling for:

Gas Premium

Drilling targets reflect relative premiums and expectations

©BEG/CEE-UT, 7

Consequences for Producers

-

1,000

2,000

3,000

0%

50%

100%

MM

BOE

US NGL Production US Oil and Liquids ProductionUS Natural Gas Production US Total Production

An Equivalent Barrel

0 2 4 6 8 10

20092010201120122013201420152016

3-Year MA FD Costs Cash Costs 10% Return

Cost Stack with 10% Return ($/BCFE)

0 10 20 30 40 50

20092010201120122013201420152016

3-Year MA FD Costs Cash Costs 10% Return

Cost Stack with 10% Return ($/BOE)

Note: CEE 2017 results expected to be broadly equivalent.CEE producer benchmarking, 16 companies, annual reports; Michot Foss analysis

• Extraordinary hunt for liquids rich (black oil) acreage as producers continue to shift portfolios

• Rapid accumulation of debt (now, deleveraging)• “Gassy” producers are lower cost but…• …if all of the cost burden was placed on methane,

would need a supporting gas price

©BEG/CEE-UT, 8

Consequences for Producers

-

10

20

30

40

50

60

$/BO

E

Annual Waterfall: (Multiple Items), (All)

Note: CEE 2017 results expected to be broadly equivalent; slight improvement in net income, more capital discipline

CEE producer benchmarking, 16 companies, annual reports; Michot Foss analysis

Bernstein Research (right), used with permission

• Challenges keeping spending in line with cash flow (better)• Large contribution of depreciation to cash flow funded

spending (too much)• Reliance on external capital markets, especially for organic

capex (M&A, property dispositions)

2009-2016 All Companies

©BEG/CEE-UT, 9

Long Term Spending and Cash Flow

(40.0)

(35.0)

(30.0)

(25.0)

(20.0)

(15.0)

(10.0)

(5.0)

-

3Q14 4Q14 1Q15 2Q15 3Q15 4Q15 1Q16 2Q16 3Q16 4Q16 1Q17 2Q17 3Q17

$/BO

E

Industry Average CEE Group Avg

Note: CEE 2017 results expected to be broadly equivalent; slight improvement in net income, more capital discipline

CEE producer benchmarking, 16 companies, annual reports; Michot Foss analysis

Bernstein Research (right), used with permission

Capex-CF

The “treadmill” shows up in the need for continuous outlays of capex, largely funded by accumulated depreciation and external capital

©BEG/CEE-UT, 10

Midstream, the Giant Sucking Sound

0

5

10

15

20

25

30

35

2009 2010 2011 2012 2013 2014 2015 2016

$/BO

E

Production Exploration Non-income Tax G&A Mktging

Expected total cash cost 2017

Expect increase in G&A Marketing

Note: CEE 2017 results expected to be broadly equivalent; slight improvement in net income, more capital discipline. CEE producer benchmarking, 16 companies, annual reports; Michot Foss analysis

“Producer push” as opposed to “demand pull” for midstream investment• Producers now much more

constrained

©BEG/CEE-UT, 11

Realizations: Expected vs Reported RevenuePositive = Realized < Expected

Bernstein Research, used with permission

Gassy companies have greater difficulty meeting realized revenue targets

©BEG/CEE-UT, 12

In Sum: State of the Industry

• Improvements in cost management, so far, but– Midstream continues to burden producers– Capex will grow again as companies try to reposition

• Acreage consolidation to pursue drilling patterns• The “cube” strategy of “wine rack” near simultaneous

completions as companies work to manage “parent-child”well interference (charts on right, proprietary project)

• The need to drill to sustain upstream businessesis quite real– “Prove up” to retain, attract new capital– Volumes to produce sufficient funding for operations

• Given these realities + predominant “gas drive”reservoirs + midstream bottlenecks + offtake = impact on prices and spreads

Mar

-17

May

-17

Jul-1

7

Sep

-17

Nov

-17

Jan-

18

Mar

-18

May

-18

Jul-1

8

Sep

-18

Nov

-18

Jan-

19

Mar

-19

May

-19

Jul-1

9

Sep

-19

Nov

-19

Jan-

20

Mar

-20

May

-20

Jul-2

0

Sep

-20

Nov

-20

Jan-

21

Mar

-21

May

-21

Jul-2

1

Sep

-21

Nov

-21

Jan-

22

Mar

-22

May

-22

Jul-2

2

Sep

-22

Nov

-22

$Mill

ions

and

$M

illio

ns

5 Yr. Development Horizon by MonthFCF Cume FCF

2017

2018

2019

2020

2021

2022

2023

2024

2025

2026

2027

2028

2029

2030

2031

2032

2033

2034

2035

2036

2037

2038

2039

2040

2041

2042

2043

2044

2045

2046

2047

2048

2049

2050

2051

2052

2053

2054

2055

2056

2057

2058

2059

2060

2061

2062

$Mill

ions

and

$M

illio

ns

Full Project Life by Year

FCF Cume FCF

Assumptions: Avg realized crude price $55; Avgrealized gas price $3.20

©BEG/CEE-UT, 13

Waha and EP-P

https://rbnenergy.com/

https://rbnenergy.com/

©BEG/CEE-UT, 14

Weekly

http://www.naturalgasintel.com/data/data_products/weekly?location_id=SLAHH&region_id=south-louisiana

Deterioration of spreads

http://www.naturalgasintel.com/data/data_products/weekly?location_id=SLAHH&region_id=south-louisiana

©BEG/CEE-UT, 15

Forward - Fixed

Forward prices of natural gas delivered for each reference period at the various locations/hubs.

http://www.naturalgasintel.com/data/data_products/forward-contracts?location_id=SLAHH&region_id=south-louisiana


©BEG/CEE-UT, 16

Forward - Basis

"Basis price" represent the differential, for each reference period, between the Henry Hub and various locations/hubs.


HENRY HUB


©BEG/CEE-UT, 17

A fix?

©BEG/CEE-UT, 18

Usefulness of Spreads

• Lure investment to bottlenecks and…• …attract monetization options…

– Gains from trade– End users

• …so long as business conditions support “optionality”.– And it can be paid for.

©BEG/CEE-UT, 19

(5.0)

(4.0)

(3.0)

(2.0)

(1.0)

-

1.0

-

2.0

4.0

6.0

8.0

10.0

12.0

Cove Point

AECO Hub

LNG import only

Major gas pipeline flows

LNG export only

LNG import (M)/export (X)

BC (Canada) Projects

Pacific Northwest

Major NGLs flows

Henry HubMarket Region

Impacted gas pipeline flows

Wah

a

12 mosthrough Jan 18: -4.3 BCFD

U.S. is about47% of Mexican

consumption (2016)

U.S. is about24% of Canadian

consumption (2016)

12 mos to Jan 18: 5.7 BCFD

2013: ~2x current NA exports by 2020

to ~9+ BCFD?As of Jan 18

~9 BCFD (4.0)

(2.0)

-

2.0

4.0

6.0

8.0

10.0

12.0

14.0

12 mos to Jan 18: -0.4 BCFD

(3.0)

(2.0)

(1.0)

-

1.0

2.0

3.0

4.0

12 mosthrough Jan 18:-1.8 BCFD

US/NAM Gas Trade

Net Imports

Michot Foss, Chapter 3, Pricing of Internationally Traded Gas, www.oxfordenergy.org; EIA; FERC

U.S. LNG

http://www.oxfordenergy.org/

©BEG/CEE-UT, 22Guillermo Turrent, CFE, Energy Mexico 2018, Jan 30, used with permission

CFE’s zonal pricing strategy intended to:• Improve signaling for

internal de-bottlenecking and expansions

• Improve price signals for imports

• Provide price signals for domestic production

PetroLida(Michot)

©BEG/CEE-UT, 23

Our Renaissance

• About 100 Projects• About $90 billion• Incremental NG

demand of ~3 BCFD

CEE industrial database

©BEG/CEE-UT, 24

Global LNG complexities…• “Low” demand growth (China, India,

Japan, and others): – Coal, nuclear, renewables have priority -

energy security – Not enough gas infrastructure (especially

storage) – Low gas market readiness – Sluggish economic growth– Japanese energy policy: nuclear,

renewables, efficiency• “Surging” global LNG supply excess

supply until the mid 2020s– Unsubscribed U.S. liquefaction capacity– Parts of contracted volumes not tied to

specific destinations

http://www.beg.utexas.edu/energyecon/template/IAEE%20Energy%20Forum_062116.pdfhttp://www.beg.utexas.edu/energyecon/thinkcorner/CEE_Advisor_Research_Note-Andy_Flower_LNG_Supply_Outlook-Aug16.pdfhttp://www.beg.utexas.edu/energyecon/thinkcorner/CEE_Research_Paper-China_and_India_Current_Future_Natural_Gas_Demand-Apr17.pdf

http://www.beg.utexas.edu/energyecon/template/IAEE%20Energy%20Forum_062116.pdf

http://www.beg.utexas.edu/energyecon/thinkcorner/CEE_Advisor_Research_Note-Andy_Flower_LNG_Supply_Outlook-Aug16.pdf

http://www.beg.utexas.edu/energyecon/thinkcorner/CEE_Research_Paper-China_and_India_Current_Future_Natural_Gas_Demand-Apr17.pdf

©BEG/CEE-UT, 25

…and rapidly shifting terrain.

Creditworthiness of buyers is a substantial risk to global LNG trade growth.

Shell LNG Outlook 2018

©BEG/CEE-UT, 26

Closing Thoughts

• How to keep the success story going– First, do no harm

• Ultimately, market will set pathway…– Cost of capital– Attraction of oil and gas for investment portfolios– Ability of producers to consolidate acreage positions

in order to sustain, improve efficiencies and get offthe treadmill (???)

– Trade, petrochemicals do not provide enough “oompf”– Gas competitiveness for electric power is key

• …perceptions will dictate

clear as mud(rocks): a forward view of natural gas · annual reports; michot foss analysis...

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