Jack Weixel (VP, Analysis) and Warren Waite (Manager, Analysis) delivered this on-demand webinar "Cruel Summer: Natural Gas Market Expectations for Summer 2017 and Beyond" on May 3, 2017.

1. Cruel Summer
Natural Gas Market Expectations for
Summer 2017 and Beyond
A PointLogic Energy Webinar
May 3, 2017

2. PointLogic Energy Suite of Services
Custom
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Award winning web interface,
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Daily supply & demand
fundamentals. Natural gas price
survey & bid week prices.
Detailed storage
estimates by EIA region
Gas processing plant
volumes and natural gas
liquid volumes by refining
district and purity product

3. I. How did we get here: Back to back winter
demand disappointment puts forward curve in
flux.
II. Summer Demand Expectations: Weather, inter-
fuel competition and exports, the changing
landscape and cruel reality of summer demand.
III. Lower 48 Production Response & Projects:
Where is the growth and how will pipeline projects
impact pace of growth?
IV. Summer Prices and Storage: Henry Hub
influences, basis expectations and storage impact
of supply and demand.
Agenda & Key Themes

4. -2.3
-0.1
0.2
-2.3 -2.1
0.1
-0.4
0.5
1.5
-0.4
DryProd
LNGIm
CanImports
Supply
Power
Industrial
Res/Com
MexEx
LNGEx
Demand
Winter 2016/17 vs. Winter 2015/16
Supply Demand
Source: PointLogic Energy Supply & Demand Report
Prod Slowdown and Demand Flub Leaves Market 1.9 Bcf/d Short vs Last Winter
Storage inventory remains elevated as only 295 Bcf incremental withdrawn vs last
winter

5. 86.0 85.8
79.7
77.5
Winter 13-14 Winter 14-15 Winter 15-16 Winter 16-17
Winter 2016/17 in Historical Terms
Winter Domestic Demand (Bcf/d)
Source: PointLogic Energy Supply & Demand Report
Were winters 13/14 and 14/15 anomalies?
Only times in history where res/com demand
averaged greater than 41.0 Bcf/d.
Are winters 15/16 and 16/17 anomalies?
HDDs averaged 16% below 8 year normal
and 23% below Winters 13/14 and 14/15.
HDDs: 3,356 3,151 2,445 2,543

6. Source: Statweather and NOAA
Summer 2017 Weather Expectation
788 739
959 977 890
2013 2014 2015 2016 8 Year
Norm
2017
Cooling Degree Days (Apr-Oct)
1000?

7. Source: EIA, PointLogic
Summer Brings More Natural Gas
Generation Capacity
0
50
100
150
200
250
300
350
400
450
500
Natural Gas Coal Nuke Hydro Wind Solar Biomass
Summer Capacity in GW – July 2016 vs. July 2017
Jul-16 Jul-17
+10 GW
-4 GW
-2 GW Flat +7 GW
+8 GW
Flat
Growth in gas-fired capacity does not necessitate growth in utilization for Summer 2017

8. Source: EIA, PointLogic
Warm Winter Also Boosted Coal Supply
40.0
45.0
50.0
55.0
60.0
65.0
70.0
Nov Dec Jan Feb Mar
Coal Supply (mmst)
Winter 15-16 Winter 16-17
+8.6
mmst
vs.
year
ago
-$3.0
-$2.5
-$2.0
-$1.5
-$1.0
-$0.5
$0.0
Delta Cost of Generation
(Coal vs. Gas in $/MMBtu)
Cost margin
increased by
$1.12 yoy in
March, $0.99
in April

9. Coal demand remains at the
mercy of gas market dynamics
• Coal demand in 2017 will be up, a function of a very weak 2016.
• CAPP and NAPP coal are most susceptible to displacement while Illinois and PRB coal
remain modestly insulated.
MISO
MISO
MISO
MISOSPP
SPP
ERCOT
Southeast
Southeast
Southeast
WECC
NYNE
NYNE
PJM
PJM
PJM
PJM
1.00
1.50
2.00
2.50
3.00
3.50
4.00
4.50
5.00
CAPP NAPP ILB PRB
Coal-to-gas delivery economics for 2017
Break-evennaturalgasprice
($/MMBtu)
© 2017 IHS
Notes: MISO = Midcontinent Independent System Operator; NYNE = New York and New England; SPP = Southwest Power Pool; ERCOT = Electric Reliability Council of
Texas; WECC = Western Electricity Coordinating Council. Coal price adjusted to gas equivalent (10,250 Btu/kWh coal versus 7,800 Btu/kWh gas).
Source: IHS Energy
Current summer strip = $3.34/MMBtu
Summer 2016 strip = $2.57/MMBtu

10. 10.0
13.0
16.0
19.0
22.0
25.0
28.0
31.0
34.0
37.0
40.0
Apr-17 May-17 Jun-17 Jul-17 Aug-17 Sep-17 Oct-17 Nov-17 Dec-17 Jan-18 Feb-18 Mar-18
Power Demand (Bcf/d) Forecast Year Ago
Avg Summer 17 Pow = 27.3 Bcf/d
Avg Summer 16 Pow = 30.1 Bcf/d
Summer 2017 Power Demand
Source: PointLogic Supply/Demand and Two Season Balanced Forecast
3.5
Bcf/
d
3.5
Bcf/
d
3.5
Bcf/
d

11. (0.1) (0.1)
(0.4)
(1.5)
(1.0)
(0.5)
-
0.5
1.0
1.5
2.0
2.5
3.0
3.5
4.0
Net Imports to the Lower 48
(Canada less Mexico and LNG in Bcf/d)
LNG Exports Surges; US Now Net
Exporter
Forecast
2017 = Net Zero Imports
-
0.50
1.00
1.50
2.00
2.50
3.00
3.50
LNG Demand vs. Capacity (Bcf/d)
Pipeline Deliveries Forecast Capacity
Sabine
Train 1
Sabine Train 4
& Cove Point
Sabine
Train 3
Sabine
Train 2

12. Summer ‘14
2.1 Bcf/d
Summer ‘15
3.1 Bcf/d
Summer ‘16
3.9 Bcf/d
Summer ‘17
4.2 Bcf/d
Pipeline Exports to Mexico is the 2nd
Largest Demand Growth Sector in 2017
• NET Mexico accounts for almost half of all U.S. exports to Mexico
- Nearly 70% of exports are from intrastates, adding uncertainty to the market
• Current and Future Growth Will Come From Texas
- Permian, Eagle Ford and Agua Dulce sourced supply

13. Mexico’s Energy Reforms
Spark Infrastructure Boom
Over 10 Bcf/d of New Pipelines Within Mexico by 2019
• Service the power
sector
• Reinforce dependability
and supply redundancy
• Offer new geographic
markets for gas

14. Export Capacity to Top 11 Bcf/d;
Border Utilization Will Take Time
This image cannot currently be displayed.This image cannot currently be displayed.
Aqua Dulce Hub
+ > 5 Bcf/d of projects within
and outside of Texas to push
gas closer to the border

15. Production Response

16. 64
66
68
70
72
74
76
78
Bcf/d
L 48 Dry Gas Production (Bcf/d)
Production (thru Mar' 18) Forecast
2017 Production Delayed
Is this the Bottom?
April’14
69.1 Bcf/d
Source: PointLogic Supply/Demand and Two Season Balanced Forecast
Summer Average
~ 70.6 Bcf/d
Winter Average
~ 75.0 Bcf/d
April’15
74.0 Bcf/d
April’16
72.3 Bcf/d April’17
69.9 Bcf/d

17. + 0.3
Bcf/d
-0.4
Bcf/d
-0.2
Bcf/d
-1.4
Bcf/d
+ 0.1
Bcf/d
+ 1.5
Bcf/d
Lower 48 Production to
Decrease 0.7 Bcf/d from
Summer 2016 to 70.6 Bcf/d.
Production: Summer 2017 vs. Summer
2016
-0.6
Bcf/d
Source: PointLogic Energy
21
22
23
24
Summer
2016
Winter
16/17
Summer
2017
15
16
17
18
Summer
2016
Winter
16/17
Summer
2017
0
1
2
3
4
Summer
2016
Winter
16/17
Summer
2017

18. -1.3
0.3 0.8 0.6
0.1
(3.0)
(2.0)
(1.0)
0.0
1.0
2.0
3.0
2014-2017 2014-2017 2014-2017 2014-2017 2014-2017
TX OH PA WV OK
Annual Gain/Loss by Influential States (Bcf/d)
-
2,000
4,000
6,000
8,000
10,000
12,000
14,000
Jan-14
May-14
Sep-14
Jan-15
May-15
Sep-15
Jan-16
May-16
Sep-16
Jan-17
Production per Rig (Mcf/d)
Marcellus
Utica
Eagle Ford
Permian
Source: EIA’s DPR
0
500
1,000
1,500
2,000
2,500
Jan-14 Jan-15 Jan-16 Jan-17
Lower 48 Rig Count
Rest of L-48
Marcellus
Utica
Eagle Ford
Permian
Source: Baker Hughes
851
A Concentrated Recovery

19. • Oil-Driven Play, next to Cushing gives it a strategic advantage, but it also
creates new challenges for moving associated natural gas.
• Similar to Permian, 2016 saw major M&A activity, breakevens<$40/bbl.
• Operators to compete for upstream services (rising cost)
• ~3.0 Bcf/d of projects to move SCOOP/STACK gas by late 2018 – 2019.
- Majority of this would connect to pipes feeding into Perryville Hub
0
10
20
30
40
50
60
Jan-14
Mar-14
May-14
Jul-14
Sep-14
Nov-14
Jan-15
Mar-15
May-15
Jul-15
Sep-15
Nov-15
Jan-16
Mar-16
May-16
Jul-16
Sep-16
Nov-16
Jan-17
Mar-17
Cana-Woodford Rig Count
Source: Baker Hughes
Oklahoma’s SCOOP and STACK
* Sooner Trails is now cancelledUsed with Permission

20. 0
200
400
600
Jan-14 Jan-15 Jan-16 Jan-17
Permian Rig Counts
NM Permian TX Permian- Delaware
TX Permian-Central TX Permian-Midland
• Permian is the most attractive play in North America, however despite
2016 resurgence new associated gas production IS NOT enough to offset
continued declines elsewhere in Texas. But for the Western states, NM-
Permian IS enough.
• Infrastructure projects across the hydrocarbon chain are planned.
• Gas wise, large volume pipeline projects to move gas to Mexico and
to Agua Dulce. By late 2019, + 3.5 Bcf/d to Agua Dulce.
Permian, Too Much of a Good Thing?
Source: Baker Hughes, PointLogic
5 TX Counties Account for 43% of Permian Rig Growth:
Loving, Reeves, Howard, Martin, Midland

21. Northeast Production Resurgence–
Where’s the Beef?
• 2017 Growth will be Focused in Utica and Marcellus-Wet
• 2017 CapEx is up > 50% YoY, 2018 supply growth will be Huuuuge.
• 2017/2018 Reliant on New Takeaway Capacity and Improved Net Backs
Source: Company Investor Presentations
Utica
Operator '17 Expectations and Side Notes
CHK 0.0 Bcf/d no notable YoY changes
Antero +0.4 Bcf/d
owns 0.8 Bcf/d on Rover,
growth is mix of OH, WV,
PA
Gulfport +0.3 Bcf/d
owns 0.15 Bcf/d on Rover
+ 0.25 Bcf/d across TGT,
CGT, TETCO projects
3 Operators make up nearly 70% of all production
WV-Wet
Operator '17 Expectations and Side Notes
Antero +0.4 Bcf/d
build out of NGL
infrastructure is essiential.
See Utica entry
EQT +0.2 Bcf/d
combination of SW PA-
Wet and WV-Wet
2 Operators make up nearly 56% of all production
NE PA-Wet
Operator '17 Expectations and Side Notes
CHK 0.0 Bcf/d
Capital deployed to oil assets,
NE acreage helf by production
Cabot 0.0 Bcf/d
Marginal NE growth, capital and
growth focused in Eagle Ford
2 Operators make up nearly 45% of all production
SW PA-Wet
Operator '17 Expectations and Side Notes
EQT +0.2 Bcf/d
combination of SW PA-Wet
and WV-Wet
Range +0.6 Bcf/d
owns 0.4 Bcf/d on Rover, 0.4
Bcf/d Rayne Xpress
2 Operators make up nearly 45% of all production

22. Northeast Gas Flows Become Slightly
Less Constrained: YTD Compare
2.9 Bcf/d
Net Canada: 0.2 Bcf/d
Net Midcon: - 2.9 Bcf/d
Net Southeast: - 3.7 Bcf/d
Net Northeast Flows: - 6.4 Bcf/d
Source: PointLogic Energy
Appalachia
Atlantic
New England∆ 3.5 Bcf/d from 2016 YTD Net Flows
∆ + 0.2 Bcf/d with Canada
∆ + 1.2 Bcf/d with Midcon
∆ + 2.1 Bcf/d with Southeast
∆ + 1.2 Bcf/d
NY/NJ
Dominion South Basis
2016 YTD: ($ 0.66)/MMBtu
2017 YTD: ($ 0.33)/MMBtu
Delta: + $0.33/MMBtu

23. Escape Routes from the Appalachia
Source: PointLogic’s Project Tracker
2017: +4.8 Bcf/d*
2018: +0.0 Bcf/d
2019: +0.0 Bcf/d
Annual Takeaway Capacity
2016 Actual: 13.9 Bcf/d Avg
2017: 8.4 Bcf/d*
2018: 5.0 Bcf/d
2019: 3.7 Bcf/d
Total: 17.1 Bcf/d
Cumulative Takeaway > 31 Bcf/d
* Assumes Projects Enter In-Service Dates as Announced
Midwest &
Canada
Gulf
Coast
Atlantic
Coast
NY/NJ,
Canada, New
England
Producers
& LDCs
Mostly Producers +
some LNG offtakers
+ 1.6 Bcf/d
from
Producers, rest
are LDCs
Mainly LDCs +
some Producers
* Includes Nexus
5.6 Bcf/d in Q4
2.5 Bcf/d in Q3

24. Northeast Projects
on the Summer Horizon
Rover Phase I:
July 2017 2,200 MMcf/d
• Gets to Defiance where gas can move N & S on
PEPL (related BH project) and ANR.
• Summer utilization is expected to be low.
• Connections to major GPP’s not until Phase II
in Nov. 2017
TETCO Gulf Markets Phase II:
August 2017 400 MMcf/d
• Phase I was for 250 (100 EQT, 250 Range) M2
to ELA
• Phase II is assumed 250 from M2 and 150 from
TX

25. Δ 5 Yr
+15 Bcf
Δ 5 Yr
+27 Bcf
Δ 5 Yr
+117 Bcf
Δ 5 Yr
+222 Bcf
Δ 5 Yr
-53 Bcf
Total U.S.
Δ 5 Yr
+299 Bcf
Storage Deltas to the 5 Year Average
Only region
with deficit
to 5 year
average =
upward price
pressure.
As the South
Central goes,
so does the US:
regional S&D
impacts price,
erodes surplus.

26. Summer 2017 vs. Summer 2016
Henry Hub and Location Basis
Source: PointLogic Energy
Wider Spread
Tighter Spread
Stronger
Basis
Weaker
Basis
HH↑

27. -0.7
0.0
-0.1 -0.8
-2.9
0.0
-0.9
0.5 1.5
-1.7
DryProd
LNGIm
CanImports
Supply
Power
Industrial
Res/Com
MexEx
LNGEx
Demand
Summer 2017 vs. Summer 2016 vs. 5 Yr Avg
Supply Demand
Source: PointLogic Energy Supply & Demand Report
Versus Summer 16
• Market 0.9 Bcf/d
Long
• Injections up by
198 Bcf.
• Summer injection
of 1,675 Bcf (vs.
1,477 Bcf).
1.5
0.6
0.0
2.0
0.5 0.2
-1.0
1.7 2.0
3.4
DryProd
LNGIm
CanImports
Supply
Power
Industrial
Res/Com
MexEx
LNGEx
Demand
Supply Demand Versus 5 Yr Avg
• Market 1.4 Bcf/d
Short
• Injections down
by 299 Bcf
• Erosion of surplus
by late August.

28. $1.50
$2.00
$2.50
$3.00
$3.50
$4.00
(500)
500
1,500
2,500
3,500
4,500
$/MMBtu
Bcf
Inventory Storage Forecast 5 YR AVG Surplus/Deficit
HH Cash Prices NYMEX as of 4/28/17
As Inventories Approach Five Year Average, Winter
is Good News for Producers and Storage
Source: EIA, PointLogic
4.0 Tcf
Nov 16 3.7 Tcf
Nov 17
2.5 Tcf
Apr 16
2.0 Tcf
Apr 17 1.7 Tcf
Apr 18

29. I. How did we get here: Back to back winter
demand disappointment puts forward curve in
flux.
II. Summer Demand Expectations: Weather, inter-
fuel competition and exports, the changing
landscape and cruel reality of summer demand.
III. Lower 48 Production Response & Projects:
Where is the growth and how do pipeline projects
impact pace of growth?
IV. Summer Prices and Storage: Henry Hub
influences, basis expectations and storage impact
of supply and demand.
Agenda & Key Themes

30. Contact Us
Jack Weixel & Warren Waite
jweixel@pointlogicenergy.com
wwaite@pointlogicenergy.com
Customer Support
Phone: 855.650.4500 ext. 1
support@pointlogicenergy.com
Sales
Phone: 855.650.4500 ext. 2
sales@pointlogicenergy.com

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estimates are available.
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Gas processing plant volumes and natural gas liquid volumes by refining district and purity product.
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