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U.S. Research

© 2016 Raymond James & Associates, Inc., member New York Stock Exchange/SIPC. All rights reserved.

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Published by Raymond James & Associates

AMERICAN GAS ASSOCIATION (AGA) FINANCE COMMITTEE MEETING

2017 INVESTMENT STRATEGIES:

SHORT-TERM COMMODITY-DRIVEN VOLATILITY PERSISTS; LONG-TERM

CAPITAL INVESTMENT THESIS IN ENERGY INFRASTRUCTURE REMAINS

BULLISH

Darren Horowitz

Energy Equity Research Analyst

(713) 278-5269

[email protected]

March 21, 2017


International Headquarters: The Raymond James Financial Center | 880 Carillon Parkway | St. Petersburg, Florida 33716 | 800 -248-8863 2

Overview

I. Current Energy Overview: Where are we Different vs. Consensus?

II. Crude Oil Outlook: The Worst is Behind Us, Bullish on Price into 2H17

A. Supply – Lower 48 production discipline, OPEC cuts, non-OPEC supply?

B. Demand – Not the problem!

III. Nat Gas Outlook: Awash in “J-I-T” Supply, Associated Gas Production and

Low Breakeven Prices Keep a Perpetual Lid on a Sustained Price Recovery

IV. NGL Outlook: Will Downstream Demand-pull Drivers Balance the Market?

Composite NGL/Ethane Price Uplift to come!

V. Capital Investment is the Theme!

VI. Current Valuations: Attractive on both an Absolute Basis vs. History and on

a Relative Basis vs. Alternatives in the Market, but When Does That Matter?

VII. Where to Invest – Defense vs. Offense: Are There any Bright Spots?

VIII. Raymond James Midstream MLP Comp Tables

IX. Risks



I. Current Raymond James’ Energy Overview

• Bullish on oil prices relative to futures strip: Crude prices move

higher in 2017, despite pronounced short-term challenges

• Long-term view remains challenging for natural gas: Supply rich

N.E. keeps a lid long-term prices – volatile differentials

• Capital Investment Part 1: Incremental capex spent through the

drillbit drives meaningful investment in energy infrastructure

• Capital Investment Part 2: Where to invest to capitalize?

– Oilfield Services Equities - overcorrected to the downside in 2015/16:

Expect a rebound in 2H17/18 U.S. oilfield services pricing; stocks will lead

– E&P Equities – Valuation agnostic, the stocks will trade with crude: Is

leverage-driven capital discipline here to stay?

– Midstream Equities – Drive to maximize our domestic hydrocarbon

resource potential provides supply assurance with less risk

• Supply growth timing/magnitude vs. Demand: Mismatches create logistical opportunities



Where are we Different vs. Consensus?

• 2017/18 oil price 40-30% higher than strip, respectively

• Oil price moves higher, sooner

• U.S. oil-field service bottlenecks could slow the supply response

– Ex: Well completion services (Pressure pumping) prices/margins

could expand higher

• Long-term U.S. oil supply MUCH higher, pushing prices lower

– U.S. supplies all incremental oil demand + some

• After 2H17 oil price increase, the forward curve becomes more

backwardated (ie: 2018 prices lower vs. 2017)

– Long-term prices average ~$50/bbl



II. Crude Oil Outlook: Why are we Bullish?

• Little excess oil capacity – first time in 40 years

• Is OPEC no longer the “balancing mechanism” to support price?

• U.S. has become lowest cost producer for oil & gas

– Most underestimate the U.S. efficiency gains

– Extraction cost falling rapidly

– U.S. oil supply is cheap, resilient, and substantial

• U.S. growth displaces offshore/international

• Shift has massive geopolitical considerations

– Stronger $, U.S. manufacturing wins, trade balances shift, global

consumers win

– Will our crude oil bbl become fully fungible on a global basis?



Member Reference OPEC Proposed OPEC Proposed RJ Pre-Cut Model RJ Model RJ Post-Cut Model

Country Production Level Adjustment Jan 2017 Production 1H17 Production Adjustment 1H17 Production

Saudi Arabia 10,544 -486 10,058 10,400 -340 10,060

Iraq 4,561 -210 4,351 4,500 -150 4,350

UAE 3,013 -139 2,874 2,950 -80 2,870

Kuwait 2,838 -131 2,707 2,800 -90 2,710

Venezuela 2,067 -95 1,972 1,940 0 1,940

Angola 1,751 -78 1,673 1,720 -50 1,670

Algeria 1,089 -50 1,039 1,110 -70 1,040

Qatar 648 -30 618 620 0 620

Ecuador 548 -26 522 530 -10 520

Gabon 202 -9 193 200 -10 190

Libya 520 0 520 500 0 500

Nigeria 1,670 0 1,670 1,630 0 1,630Iran*** 3,707 +90 3,797 3,700 0 3,700

Total OPEC 33,158 -1,164 31,994 32,600 -800 31,800

Source: OPEC, Bloomberg, Raymond James research

*Reference base to crude o il production adjustment is October 2016 levels, except Angola for which September 2016 is used,

and the numbers are from secondary sources (other than OPEC), which do not represent a quota for each member country

** Libya and Nigeria production based on Bloomberg data

*** Adjusted Iran numbers from OPEC agreement to reflect current production.

“Headline” vs. “Real” OPEC Cuts; True impact on our model



Iran, Saudi Arabia and Iraq: Production Ramps…What lies Ahead?

8.55

8.9

9.34 9.37

9.65

9.77

9.6

9.23

8.99

9.27

9.82

9.49 9.469.5

9.629.53

9.77

10.29 10.2710.18 10.21

10.33

10.6210.56

10.00 10.00

10.60

10.40

1Q11 2Q11 3Q11 4Q11 1Q12 2Q12 3Q12 4Q12 1Q13 2Q13 3Q13 4Q13 1Q14 2Q14 3Q14 4Q14 1Q15 2Q15 3Q15 4Q15 1Q16 2Q16 3Q16 4Q16 1Q17E 2Q17E 3Q17E 4Q17E

Saudi Arabia Crude Production (excl. Neutral Zone), 2011-2017E (MMbpd)

IEA Reported Saudi Arabia Crude Production Raymond James ForecastSource: IEA, Raymond James ResearchSource: IEA, Raymond James ResearchSource: IEA, Raymond James Research

2.69

2.92

3.073.12

3.03

3.16

3.043.08

3.293.33

3.22

3.48 3.5

3.94

4.25 4.28 4.28 4.29

4.43

4.61

4.40 4.40

4.50 4.50

1Q12 2Q12 3Q12 4Q12 1Q13 2Q13 3Q13 4Q13 1Q14 2Q14 3Q14 4Q14 1Q15 2Q15 3Q15 4Q15 1Q16 2Q16 3Q16 4Q16 1Q17E 2Q17E 3Q17E 4Q17E

Iraq Crude Production, 2012-2017E (MMbpd)

IEA Reported Iraq Crude Production Raymond James ForecastSource: IEA, Bloomberg, Raymond James Research

3.63 3.65

3.53 3.51

3.37

3.14

2.81

2.71 2.70 2.682.64

2.71

2.812.84

2.79 2.80 2.822.85 2.87 2.89

3.15

3.59

3.673.70 3.70

1Q11 2Q11 3Q11 4Q11 1Q12 2Q12 3Q12 4Q12 1Q13 2Q13 3Q13 4Q13 1Q14 2Q14 3Q14 4Q14 1Q15 2Q15 3Q15 4Q15 1Q16 2Q16 3Q16 4Q16 1Q17E 2Q17E 3Q17E 4Q17E

Iran Crude Production, 2011-2017E (MMbpd)

IEA Reported Iran Crude Production Raymond James ForecastSource: IEA, Raymond James Research

EU embargois announced

Final nuclear agreement is announced

Up 720,000 bpd!

3.80 3.753.76



• U.S. Liquids Production Has Rolled Over; Is the Magnitude Enough?

• Liquids production increased to ~12.5 MMBbls/d (-330 MBbls/d YOY).

• Yes, U.S. E&P company capital budgets fell ~40-50% YOY, but was that enough?

• What about deferred well completions? Or will the offset be well/production efficiencies +20-30%?

• What Rig Count Keeps Production Low Enough to Rebalance the Market?

• RJ 2017 Outlook: Roughly 650-700 rigs today increasing to average 850 in 2017

• 10/10/14-5/27/16: Peak-to-trough the U.S. Oil rig count fell 80% (1,609 to 316)…How fast will it recover?

• RJ Global Crude Inventory Outlook suggests: 2017 builds of -0.9 MMBpd (inc. missing bbls adj.)

• Lag effect: How long will it take before a supply correction is fully reflected in stock valuations?

Does Price Matter? Can a $50/Bbl Long-term Oil Price Environment Support Incremental

U.S. Crude Oil Infrastructure Investment?

0

1,000

2,000

3,000

4,000

5,000

6,000

7,000

8,000

9,000

10,000

11,000

12,000

13,000

Jan

-13

Ap

r-1

3

Jul-

13

Oct

-13

Jan

-14

Ap

r-1

4

Jul-

14

Oct

-14

Jan

-15

Ap

r-1

5

Jul-

15

Oct

-15

Jan

-16

Ap

r-1

6

Jul-

16

Oct

-16

Jan

-17

Ap

r-1

7

Jul-

17

Oct

-17

Jan

-18

Ap

r-1

8

Jul-

18

Oct

-18

U.S. Oil Production (MBbl/d)MBbl/d

GOM

Estimates

Source: EIA, HPDI, Raymond James Research

1,169

1,665

1,035

-370

414

1,284

-800

-600

-400

-200

0

200

400

600

800

1,000

1,200

1,400

1,600

1,800

2013 2014 2015 2016 2017 2018

Y/Y

U.S

. Liq

uid

s P

rod

uct

ion

Gro

wth

(M

Bb

l/d

)

U.S. Liquids Production Growth

Total US LiquidsSource: EIA, HPDI, Raymond James Research

507

850 1,100

Rigs

97618591761

U.S. Rig Count

Rigs



Permian Basin Overview: While Currently Overbuilt, Robust Permian Growth Outlook Will

Necessitate Capacity Additions (Expansions + Newbuilds)

• While pricing pressure seen prior to 2015 has eased with takeaway pipeline start-ups out of the basin, overcommitted volume dedications

(MVCs) and declining production has led to increased competition for Midland barrels, pushing Midland WTI to a premium versus Cushing.

• We see Permian production moving from ~2.1 million bpd today, to over 3.0 million bpd by the end of 2018. Our E&P team models

Permian production growing by ~400,000/500,000 bpd in 2017/2018, to reach over 3.0 million bpd by the end 2018.

• In our view, existing capacity, when combined with planned projects, and potential low-cost expansions, offer enough capacity to

cover Permian production growth through 2018 (albeit takeaway capacity appears to get tight in early 2018).

– Existing Capacity: 2.6 MMbpd (~2.2 million bpd of takeaway pipeline capacity and ~450,000 bpd of local refining demand).

– Planned/announced capacity additions: ~710 Mbpd (EPD’s 450 Mbpd Midland-Sealy newbuild, MMP/PAA’s 100 Mbpd BridgeTex expansion,

SXL’s 100 Mbpd Permian Express III expansion and PAA’s 60 Mbpd Cactus expansion, ).

– Potential low-cost expansions: ~270 Mbpd (SXL’s 200 Mbpd Perman Express III Expansion #2 and ETP’s 70 Mbpd Lone Star Crude Conversion)

• Looking further out (beyond 2018), it appears that new-build/greenfield takeaway pipeline will need to be pursued to avoid constraints.

($21)

($18)

($15)

($12)

($9)

($6)

($3)

$0

$3

1/4/2010 1/4/2011 1/4/2012 1/4/2013 1/4/2014 1/4/2015 1/4/2016 1/4/2017

$ p

er

Bb

l

Permian DifferentialsWTI Midland vs. Cushing

WTI Midland-WTI Cushing

Zero

Avg. Transportation Cost (Midland-Cushing)Source: Bloomberg, Raymond James research

0

500

1,000

1,500

2,000

2,500

3,000

3,500

1Q12 4Q12 3Q13 2Q14 1Q15 4Q15 3Q16 2Q17E 1Q18E 4Q18E

Economic Permian Crude Takeaway Capacity vs. Production

Refinery Capacity Existing Pipeline Capacity

Bridgetex Expansion Cactus Expansion

Permian Express III Expansion Midland-Sealy (Newbuild)

Production

Source: DOE, HPDI, Raymond James research *Analysis excludes rail capacity

Thousand BPD

Takeaway constraints in late 2012/early 2013 and mid-2014 led to blowout in Permian differentials

Takeaway capacity utilizationto tighten up again in late 2017/early 2018

Forecast



Demand isn’t the Problem; Price-induced Propensity to Consume Exists in the U.S.

• U.S. gasoline demand has been remarkably strong as low prices at the pump and continued employment

growth have boosted demand.

• RJ estimated 3% gasoline demand growth in 2015 at the beginning of the year and actual growth came

in at 2.9%-3.4% (depending on the data source referenced).

• RJ estimated 2.3% total petroleum demand growth in 2015 at the beginning of the year and actual

growth came in at 2.3%-2.8% (depending on the data source referenced).

• Our 2016 estimate from the beginning of the year called for total petroleum demand growth of 1.0%.

The most recent data shows YTD increases of 0.2%-1.6% (depending on the data source referenced).

• For 2017 we estimate total petroleum demand growth of 1.0%. The most recent weekly data shows

YTD decreases of ~0.6% (on tough y/y comps).

2.30%

1.52%

2.26%

2.84%

RJ Estimate IEA Estimate 2015 "Monthly" Actual 2015 "Weekly" Actual

2015 U.S. Total Petroleum Products Demand (% Change)

Source: EIA, IEA

1.00%

0.57%

0.40%

1.60%

RJ Estimate IEA Jan Estimate 2016 "Monthly" ActualYTD

2016 "Weekly" ActualYTD

2016 U.S. Total Petroleum Products Demand (% Change)

Source: EIA, IEA



….and Across the Rest of the World?

• Global oil demand growth revised +70 mbbls/d = +1.26 mmbbls/d 2017 vs. 2016

• China distillate demand has lagged – but a growing middle class is shifting the country

towards a consumer based economy driving growth in gasoline.

• “Transportation fuels” have accounted for ~66% of the growth over the past 3 years

• Chinese auto sales have averaged ~40% annual growth over the past 5 years

• RJ estimates total demand growth of 370 MBpd and 300 MBpd for 2017 and 2018

-

100,000

200,000

300,000

400,000

500,000

600,000

700,000

800,000

900,000

China SUV Sales

Source: National Bureau of Statistics of China, Bloomberg

Average annual growth of ~40% since 2011.

0.89

0.48

0.59

0.53

0.42

.77

0.28 0.30

0.00

0.10

0.20

0.30

0.40

0.50

0.60

0.70

0.80

0.90

1.00

Chinese Demand Growth by Product (Million Bpd)Other

Middle Class Transportation (Gas/Jet)

Estimates

Total

Source: Bloomberg, IEA, National Bureau of Statistics of China, RJ Research

0.37

Transportation accounts for around half of 4 yr avg. growth



What Does This Mean for the Global Supply/Demand Balance?

0.85

-0.29

-0.73

-0.08

-0.77

-0.97

-0.77

-1.01

0.230.35

-0.22

-0.48

-1.5

-1.0

-0.5

0.0

0.5

1.0

1Q16 2Q16 3Q16 4Q16 1Q17E 2Q17E 3Q17E 4Q17E 1Q18E 2Q18E 3Q18E 4Q18E

Imp

lie

d B

uil

d (

Dra

w)

-A

fte

r M

issi

ng

Ba

rre

ls

(MM

bp

d)

Est. Quarterly Global Petroleum Inventory Builds (Draws)

CurrentBuild (Draw) Est.Source: IEA, Raymond James research

29.6

30.6

30.7

31.3

32.0

31.831.8

31.6

31.4

30.8

30.1

29.5

29

30

31

32

1Q

15

2Q

15

3Q

15

4Q

15

1Q

16

2Q

16

3Q

16

4Q

16 E

1Q

17 E

2Q

17 E

3Q

17 E

4Q

17 E

OE

CD

Da

ys o

f S

up

ply

OECD Days of Supply

RJ Forecasted Days of Supply Normalized Level

Source: IEA, Raymond James research (Assumes 1/2 the inventory build goes to OECD inventories)

Normalized OECD days of supply level of 30 days

Source 2014A 2015A 2016E 2017E 2018E

Previous Year Build/Draw -0.7 0.4 1.3 -0.1 -0.9

U.S. Supply Growth 1.8 1.0 -0.4 0.3 1.3

Other Non-OPEC Non-U.S. 0.5 0.5 -0.3 -0.1 0.1OPEC Supply Growth 0.1 1.2 1.1 0.2 0.5

Saudi Arabia 0.1 0.6 0.3 -0.2 0.2

Iraq 0.3 0.7 0.4 0.0 0.0

Iran 0.1 0.0 0.7 0.2 0.0

Total Global Supply 2.4 2.7 0.5 0.4 2.0

RJ Demand (incl. "Missing Bbls") 1.2 1.9 1.8 1.2 1.1

IEA Demand Estimate 1.1 2.0 1.5 1.3 N/A

Inventory Build Est. 0.4 1.3 -0.1 -0.9 0.0

Source: IEA, Raymond James research

Oil Supply-Demand: Year-Over-Year Changes

(MMbpd)

BULLISH



Bottom line: Where Does This Leave our Crude Oil Price Deck?

Q1 16A Q2 16A Q3 16A Q4 16A 2016A

$33.63 $45.60 $44.88 $49.29 $43.00

$35.21 $46.01 $45.82 $51.06 $45.00

Q1 17E Q2 17E Q3 17E Q4 17E 2017E

$53.04 $54.76 $55.67 $55.97 $54.86

$60.00 $70.00 $75.00 $75.00 $70.00

$63.00 $73.00 $78.00 $78.00 $73.00

Q1 18E Q2 18E Q3 18E Q4 18E 2018E

$56.05 $56.02 $55.91 $55.86 $55.96

$70.00 $65.00 $65.00 $60.00 $65.00

$73.00 $68.00 $68.00 $63.00 $68.00

Long-Term Forecast

$56.39

$60.00

$63.00

Source: Bloomberg, Thomson Reuters, Raymond James research

WTI Futures

2019 (+)

RJ WTI

RJ Brent

2018

WTI Futures

RJ WTI

RJ Brent

2017

WTI Futures

2016

Actual Brent

RJ WTI

RJ Brent

Actual WTI

RJ&A Oil Price Forecast (February 2017)



Where Could we Be Wrong on Oil?

Bearish:

• Glut in Total OECD/Domestic Crude+product Inventories:

• ~1.5 Bbbls/d/1.35Bbbls (+9%/+20% above 5-yr avg)

• U.S. Crude Inventories: 520 mmbbls (+35% vs. 5-yr avg)

• Hyperbolic U.S. $ Risk?

• Upward supply growth revisions? EIA just raised U.S. shale-oil production

growth expectation by 100 mbpd in April (~5mmbbls/d)!

• Further U.S. Efficiency/Technological gains lowering the cost profile

• OPEC “Real” Cuts? 24 Producers Agreed to Cut Output….and those cuts

are set to “expire” in June (5/25 decision to extend)• Cut “Compliance” was Fake News: Yes, OPEC output was 31.96 mmbbls in Feb

(reflected almost 100% compliance), but S.A. cut ~750 mbpd (50% more than

stated ~0.5mbpd cut) was the reason

• True cuts? Russia, Iraq, and UAE?

• Saudi getting frustrated? Was S.A. output +10mmbbls/d in Feb, reversing ~33%

of Jan’s cuts? Will S.A. continue to “bear the burden of free-riders?”

• Non-OPEC supply growth revised higher?

Bullish:

• Non-U.S., Non-OPEC supply declines? Geopolitical Risk?



III. Unconventional Plays are Redefining the Growth Potential of U.S. Natural Gas Supply

• Higher Expected Productivity from Onshore Resource Plays (i.e., legacy Barnett shale, etc)

– Barnett rig count decreases, but production doesn’t; Well productivity now ~5%-25% better?

• Increased Drilling Activity in Shale Plays

– Horizontals represent ~80% of total rig count; large majority focused on oil-related drilling

– Shale plays contribute to ~50% of current U.S. natural gas production

– Major shale plays are 70%+ of incremental production; Could hold ~1,000 Tcf of recoverable gas

• Could Unconventional Gas Production be 66% of Total U.S. Supply by 2035? (INGAA forecast)

• RJ Estimates: Production roughly flat in 2016, but back up ~0.5 Bcf/d in 2017, before gaining as much

as 5 Bcf/d in 2018!

05,000

10,00015,00020,00025,00030,00035,00040,00045,00050,00055,00060,00065,00070,00075,00080,00085,00090,000

Jan

-13

Ap

r-1

3

Jul-

13

Oct

-13

Jan

-14

Ap

r-1

4

Jul-

14

Oct

-14

Jan

-15

Ap

r-1

5

Jul-

15

Oct

-15

Jan

-16

Ap

r-1

6

Jul-

16

Oct

-16

Jan

-17

Ap

r-1

7

Jul-

17

Oct

-17

Jan

-18

Ap

r-1

8

Jul-

18

Oct

-18

U.S. Dry Gas Production (Mmcf/d)MMcf/d

Non-major plays

Estimates


Growth Resumes in 2017

0

5000

10000

15000

20000

25000

Jan

-12

Ma

y-1

2

Se

p-1

2

Jan

-13

Ma

y-1

3

Se

p-1

3

Jan

-14

Ma

y-1

4

Se

p-1

4

Jan

-15

Ma

y-1

5

Se

p-1

5

Jan

-16

Ma

y-1

6

Se

p-1

6

Jan

-17

Ma

y-1

7

Se

p-1

7

Jan

-18

Ma

y-1

8

Se

p-1

8

Ga

s P

rod

uct

ion

(M

cf/d

ay

)

New Production Per Rig by Play (Major Gas Plays)

Marcellus Utica Haynesville

Sources: EIA, HPDI, and Raymond James Research



Northeast a Game-Changer: Pipeline Additions To Improve Basis, Spur Production…

6

8

10

12

14

16

18

1Q14

2Q14

3Q14

4Q14

1Q15

2Q15

3Q15

4Q15

1Q16

2Q16

3Q16

4Q16

1Q17

2Q17

3Q17

4Q17

1Q18

2Q18

3Q18

4Q18

1Q19

2Q19

3Q19

4Q19

1Q20

2Q20

3Q20

4Q20

Northeast Marcellus Supply & Demand Balance (Bcf/d)NE PA DemandColumbia (TRP)Dominion (D)Kinder Morgan (KMI)National Fuel Gas (NFG)Spectra (SEP)Williams (WPZ)Base NE PA CapacityNE PA Production

Source: Company/partnership data, Raymond James research, EIA.

RJ Estimates

RJ Estimated Northeast Marcellus Base Takeaway Capacity

RJ Estimated Utica & SW

Marcellus Takeaway

Capacity Additions

0

5

10

15

20

25

1Q14

2Q14

3Q14

4Q14

1Q15

2Q15

3Q15

4Q15

1Q16

2Q16

3Q16

4Q16

1Q17

2Q17

3Q17

4Q17

1Q18

2Q18

3Q18

4Q18

1Q19

2Q19

3Q19

4Q19

1Q20

2Q20

3Q20

4Q20

Utica and SW Marcellus Supply & Demand Balance (Bcf/d)SW PA / WV / OH DemandBoardwalk (BWP)Columbia (TRP)Dominion (D)Energy Transfer (ETP)EQT Midstream (EQM)Kinder Morgan (KMI)Spectra (SEP)Tallgrass (TEP)TransCanada (TRP)Williams (WPZ)Base SW PA / WV / OH CapacitySW PA / WV / OH Production

Source: Company/partnership data, Raymond James research, EIA.

RJ Estimates

RJ Estimated Utica and Southwest Marcellus Base Takeaway Capacity

RJ Estimated Utica & SW

Marcellus Takeaway

Capacity Additions

-$1.08

-$0.93

-$0.81-$0.75

-$0.66-$0.60

-$1.30

-$1.20

-$1.10

-$1.00

-$0.90

-$0.80

-$0.70

-$0.60

-$0.50

-$0.40

-$0.30

-$0.20

-$0.10

$0.00

$0.10

2014 2015 2016 2017 2018 2019

$/M

MB

tu

Forecasted Avg. Northeast Differentials to Henry Hub

Differential Range (+/-$0.10/MMBtu)

Source: Bloomberg, Raymond James Research.

Modest improvement to Northeast differentials as pipelinecapacity comes online.

Northeast gas prices had extreme discounts to HHub in 2014-16!

Premium to HHub

Discount to HHub Forecast

-$2.00

-$1.50

-$1.00

-$0.50

$0.00

$0.50

1Q17

4Q16

3Q16

2Q16

1Q16

4Q15

3Q15

2Q15

1Q15

4Q14

3Q14

2Q14

1Q14

4Q13

3Q13

2Q13

1Q13

4Q12

3Q12

2Q12

1Q12

Bas

is D

iffe

rent

ial t

o H

enry

Hu

b ($

/MM

Btu

)

Marcellus & Utica Pricing Hubs Differential to Henry Hub

Columbia TCODominion NorthDominon SouthTETCO M2TGP Zone 4 - Marcellus

Source: Bloomberg, Raymond James research.

Producers have started taking advantage of Columbia pricing (making its spread widen slightly). Other differentials have been much wider, but narrow each winter.



…But Natural Gas Supply Growth Slowing and Now Almost Flat Y/Y

• Core rig count driven U.S. gas production expected to end 2016 relatively flat (on

decreased drilling activity)…

• …but we expect to see U.S. gas supply supported through Marcellus pipeline takeaway

capacity additions (~4 Bcf/d) via drilled and uncompleted wells

• ~1 Bcf/d of pipeline capacity step-up should be filled by increase in Marcellus/Utica production (i.e.,

newly drilled/completed wells)

• Remaining +2 Bcf/d of capacity will be partially filled (from shut-in and DUC’s)

• In total, our model has 2017 U.S. gas supplies up ~0.5 Bcf/d...with 2018 up +5 Bcf/d!

-3.00

-1.00

1.00

3.00

5.00

7.00

9.00

Jan

-13

Mar

-13

May

-13

Jul-

13

Sep

-13

No

v-1

3

Jan

-14

Mar

-14

May

-14

Jul-

14

Sep

-14

No

v-14

Jan

-15

Mar

-15

May

-15

Jul-

15

Sep

-15

No

v-1

5

Jan

-16

Mar

-16

May

-16

Jul-

16

Sep

-16

No

v-1

6

Ye

ar-o

ver-

Ye

ar S

up

ply

Gro

wth

, Bcf

/d

YOY EIA 914 Supply Growth Breakdown

Onshore Offshore Lower 48 States

Source: EIA (November 2016), Raymond James research, Updated 1/31/2017

-5.0

-3.0

-1.0

1.0

3.0

5.0

7.0

9.0

Total Dry Gas Production Y/Y Growth

Dry Gas Plays Wet Gas Plays Oil Plays Other Total

Source: HPDI, EIA, Raymond James Estimates

Bcf/d

Production from dry gas plays rolls over in mid-2016

Associated gas production

Planned Northeast pipeline additions are not incorporated into our model and help boost production in 2016 and 2017.

gas production from non-major plays



Demand Pull: Industrial Gas Demand ~2.5 Bcf by 2020; What about LNG, Exports to Mexico?

• Industrial demand eroded in Gas Year 2015 (down 1.8 Bcf/d), but picked up steam in Gas

Year (up 0.3 Bcf/d)

• Led by petrochemical, ammonia plants, methanol, fertilizer, and gas-to-liquids, we should

see industrial consumption pick up again over 2017-2020

• Cumulative capacity additions are tracking to be ~1.7 Bcf/d by 2018 and up to ~2.5 Bcf/d

by 2020

• U.S. LNG Exports are forecasted to reach ~8.3 Bcf/d by 2020 (right chart)

• Cheniere Energy’s Sabine Pass exported ~0.3 Bcf/d in 3Q16

• We expect an incremental ~10 Bcf/d of U.S. export capacity to come online by 2020

• LNG forecasted to account for ~15% of global gas demand by 2030! (Cheniere Energy)

• Other demand: Exports to Mexico expected to be ~7 Bcf/d by 2020

0

2

4

6

8

3Q15 4Q15 1Q16 2Q16 3Q16 4Q16 1Q17 2Q17 3Q17 4Q17 1Q18 2Q18 3Q18 4Q18 1Q19 2Q19 3Q19 4Q19

Bcf

/d

U.S. LNG Export Forecast (Bcf/d)

Cameron LNG Corpus Christi Cove Point Elba Island Freeport Sabine PassSource: Company reports, Raymond James research



Natural Gas Should Rebound in 2H17, But L-T We Have Plenty of Gas

• Feeling better about the U.S. natural gas price “set-up” for the next few years

• Our gas model is ~1 Bcf tighter Y/Y and summer 2017 storage ends at a relatively bullish ~3,700 Bcf

• We are structurally conservative on U.S. natural gas prices over the long-term

• Supply growth potential in 2H17 and beyond keeps our outlook cautious

• Incremental infrastructure must be built to accommodate multi-year production ramp

• Longer term, we see natural gas prices at $3/MMBtu in light of our lower long-term oil price forecast

and attractive producer economics.

2016 Q1 16A Q2 16A Q3 16A Q4 16A 2016A

New RJ Gas $2.01 $1.85 $2.85 $2.94 $2.41

2017 Q1 17E Q2 17E Q3 17E Q4 17E 2017E

Bloomberg Consensus $3.03 $3.00 $3.00 $3.19 $3.06

NYMEX Futures $3.70 $3.56 $3.57 $3.63 $3.61

Old RJ Gas $3.50 $3.25 $3.00 $3.25 $3.25

New RJ Gas $3.50 $3.25 $3.00 $3.25 $3.25

2018 Q1 18E Q2 18E Q3 18E Q4 18E 2018E

Bloomberg Consensus $3.08 $3.08 $3.08 $3.08 $3.08

NYMEX Futures $3.71 $2.93 $2.93 $3.00 $3.14

Old RJ Gas $3.25 $3.00 $2.75 $3.00 $3.00

New RJ Gas $3.65 $3.50 $3.35 $3.50 $3.50

2019 (+) Long-Term Forecast

Bloomberg Consensus $3.20

NYMEX Futures $3.00

Old RJ Gas $2.50

RJ Long-Term Gas $3.00

Source: Bloomberg, Thomson Reuters, Raymond James research

RJ&A Henry Hub Natural Gas Price Forecast (January 2017)

-0.6

-0.7

-0.8

-0.7

-0.4

-0.2

0.0

0.1

0.2

0.5

1.4

-1.0 0.0 1.0 2.0

Total

Weather

Mexico

LNG

Canada

Industrial

Liquids

Base Power

Nuke/Hydro

Supply

Cswitching

Ending Storage Estimates: Winter: 1,989 Bcf Summer: 3,671 Bcf

2017 Nov/Nov Theoretical Change in StorageTighter

Bullish

Looser

Bearish


-1.2

-1.2

-1.0

-0.5

-0.3

-0.2

0.0

0.0

0.1

5.7

-2.0 -1.0 0.0 1.0 2.0 3.0 4.0 5.0 6.0

Total

Weather

LNG

Mexico

Industrial

Cswitching

Canada

Liquids

Nuke/Hydro

Base Power

Supply

Ending Storage Estimates: Winter: 1,579 Bcf Summer: 3,848 Bcf

2018 Nov/Nov Theoretical Change in Storage

TIGHTER LOOSER

BULLISH BEARISH


1.4

This assumes

$3.50 Gas



IV. NGL Outlook: After a Tough Stretch, Could Things Be Turning Around in 2017?

Previous trends:

• Growing rich-gas and associated gas production led to full NGL inventories, larger basis differentials

(infrastructure constraints lessened, but not enough), and persistent ethane rejection (~500 Mbpd)

• Natural gas prices typically set the price floor for NGLs (i.e., ethane).

• 2015 propane/butane market loosened (warm weather, moderated demand despite LPG exports – Edmonton

propane prices were negative) led to competitive pricing vs. ethane and increased feedstock switching

• Petrochemical and refined product (RPP) supply/demand fluctuations will set NGL prices in competition with

oil-based alternatives

Plenty of questions out there for 2017-2018. Our View: Favorable N.A. dynamics bolster light-end NGLs’

competitive advantage to ethylene producers long-term!

• Supply

• Are we now seeing processing and fractionation capacity growth pick back up?

• Are the rate of decline of NGLs from legacy gas basins higher than expectations?

• Will oil price stabilization (or just Permian growth) lead to abundant, cheap supplies of ethane?

• Demand

• Increased LPG exports and purity ethane exports have begun (and more is coming), already shrinking

export spreads – have we already over-saturated global markets (i.e., disappointing Chinese demand)?

• Will the cost advantage of U.S. ethane persist (3rd cheapest globally, behind Middle East, Alberta, CA)?

• Crude curve is in contango – Will spread between naphtha and ethane persist?

• Petchems investing billions in world-scale crackers: What utilization rates? How many more plants?

• Ethane-to-ethylene cracking capacity additions on the horizon, but will projects slide later?

• Could we see more dehydrogenation projects for propane, butane and/or iso-butane?

• Price relationships

• Higher NGL-to-crude ratio (currently in the 40%-50% range) – will this hold?

• Gas-to-crude ratio has shrunk recently on weakness in gas – will this hold?



NGL Supplies Have Been Fairly Resilient Short-term…Grow L-T On Ethane Recoveries?

• NGL production levels finally slowing down, but ethane recoveries support supplies

• Latest data: November 2016 EIA NGL production at 3.6 MMbpd (now up 2.9% Y/Y)

• Before the recent pause, production had been among the highest producing months ever!

• 2020 NGL production could nearly double 2012 average including feasible “max” recovered ethane (~4.5 MMBpd vs. 2.4 MMBpd total NGLs)

• Ethane could grow from ~1.1 MMbpd in 2014 to ~1.9 MMbpd in 2020!

• Biggest risk? Slowdown in E&P appetite for long-term “demand-charge” gathering, processing, and fractionation contracts

• Will the broader energy market turn around quickly enough for midstream to contract and construct 2018+ NGL processing/fractionation capacity additions?

0

400

800

1,200

1,600

2,000

2,400

2,800

3,200

3,600

4,000

Jan-

13

Apr

-13

Jul-

13

Oct

-13

Jan-

14

Apr

-14

Jul-

14

Oct

-14

Jan-

15

Apr

-15

Jul-

15

Oct

-15

Jan-

16

Apr

-16

Jul-

16

Oct

-16

Jan-

17

Apr

-17

Jul-

17

Oct

-17

Jan-

18

Apr

-18

Jul-

18

Oct

-18

U.S. NGL Production (MBbl/d)Bakken

Barnett

Eagle Ford

Niobrara

Marcellus

Midcon

Fayetteville

Haynesville

Permian

Utica

Non-MajorPlays

MBbl/d

Non Major Plays

Permian

Estimates


10%

5%

6%

11%

38%

6%

5%

5%

11%2%

November 2016 EIA Plant NGL Production by Region

PADD 1

Ind., Ill. and Ky.

Minn., Wis., Dak.

Okla., Kans., Mo.

Texas Inland

Texas Gulf Coast

La. Gulf Coast

N. La., Ark

New Mexico

PADD 4

PADD 5

Source: EIA, Raymond James Research

PADD 2 spans IN, IL, MN, WI, ND, SD, OK, KS, MO, etc.

PADD 3 spans TX, LA, AR, NM, etc.

PADD 1PADD 5

PADD 4

Texas

Marcellus & Utica

Midcon & Others



Competitive Cracking Margins Today, But Ethane Should Grow Market Share L-T

• As of the end of December 2016, ethane was the most preferred feedstocks for ethylene producers (~$0.26/lbnet margins), with propane (~$0.18), naphtha (~$0.17) and nutane following behind (~$0.11).

• Despite rising co-products values (e.g., tight supply/increased demand for propylene) and despite short-term attractiveness of alternative feedstocks (propane/N-butane), ethane expected to remain in the driver’s seat for ethylene production over the longer-term (ethane ~50% market share historically, +60% moving forward).

• Ethylene steam cracker feedstock and utilization statistics for 4Q16:

• Cracker utilization 92.1% (vs. 93.6% in 4Q15)

• Ethane 1.041 MMbpd for 60.6% of total feedstock (vs. 1.065 MMbpd and 61.8% in 4Q15)

• NGL barrel 91.3% of U.S. steam cracker feedstocks (vs. 92.5% in 4Q15)

• Mt. Belvieu fractionation utilization should stay solid (EPD, Targa, and Lone Star/ETP), with some additions in the Marcellus/Utica (MPLX, WPZ JVs, others)

0%

10%

20%

30%

40%

50%

60%

70%

80%

90%

100%

0

200

400

600

800

1,000

1,200

1,400

1,600

1,800

2,000

Ethane Propane

Butane Naphtha

Gas Oil Steam Cracker Utilization Rate

MB

PD

Monthly US Steam Cracker Feedstocks and Utilization Rates (1/2008-12/2016)

Source: Hodson data, Raymond James research9/08 Data Impacted for Comparability Purposes by Hurricane Ike

($0.15)

($0.05)

$0.05

$0.15

$0.25

$0.35

$0.45

$0.55

$0.65

Jan

-14

Ap

r-14

Jul-

14

Oct

-14

Jan

-15

Ap

r-15

Jul-

15

Oct

-15

Jan

-16

Ap

r-16

Jul-

16

Oct

-16

Jan

-17

$ p

er L

b o

f Et

hyl

ene

Ethylene Profit Margin by FeedstockEthanePropaneNaphtha

Source: Bloomberg, Raymond James research. Priced 2/24/17, based on Friday ("week-end") pricing.



Ethane Market Dynamics: Are we setting up for a 2H17/2018 Price Spike?

2014A 2015A 2016E 2017E 2018E 2019E 2020E

Base Cracker Demand 827 824 718 800 800 800 800

Conversions/Expansions 211 234 317 321 334 334 334

Total Risked Newbuilds 0 0 0 63 394 435 459

U.S. Exports (Marine & Pipeline) 37 68 120 279 289 289 289

Total Demand 1074 1126 1155 1463 1817 1858 1882

Total Potential Ethane Supply 1363 1620 1694 1751 1946 2066 2134

Ethane Production 1071 1130 1157 1479 1825 1864 1893

Ethane Rejection 341 518 538 301 149 214 253

0

200

400

600

800

1,000

1,200

1,400

1,600

1,800

2,000

2,200

2,400

2014A 2015A 2016E 2017E 2018E 2019E 2020E

Mb

pd

U.S. Ethane Supply and Demand Progression

Base Cracker Demand Conversions/ExpansionsHigh Probability Newbuilds Moderate Probability NewbuildsU.S. Exports (Marine & Pipeline) Low Probability Newbuilds

Source: EIA, Bentek, Hodson, Company data, Raymond James research.

Much tighterethane market!

Owner / Operator Location

Estimated

Capacity

MMlbs/Yr

Ethane

Cracking

(Mbpd)

Estimated

CompletionProbability

Oxychem / Mexichem Ingleside, TX 1,220 33 1Q17 High

Dow Chemical (DOW) Freeport, TX 3,300 90 3Q17 High

ChevronPhillips Chem Cedar Bayou, TX 3,300 90 3Q17 High

Formosa Plastics Corp. Point Comfort, TX 2,650 70 4Q17 High

ExxonMobil Baytown, TX 3,300 90 4Q17 High

Indorama Ventures Olefins Carlyss, LA 750 20 4Q17 High

Sasol LTD Lake Charles, LA 3,300 90 2Q18 High

Shin-Etsu (Shintech) Plaquemine, LA 1,100 32 2Q18 High

Axiall & Lotte Chemical Lake Charles, LA 2,200 60 2Q19 High

Shell Chemicals Neaver Co., PA 85 2021 High

Total 21,120 575

Ethylene Cracker Capacity Currently Under Construction

Source: EIA, Benktek, Company data, Raymond James Research

Owner / Operator Location Capacity (Mbpd) Online Date Type

Mariner West - SXL Houston, PA 50 4Q13 Pipeline

Vantage - Pembina North Dakota 40 2Q14 Pipeline

Marcus Hook Terminal - SXL Marcus Hook, PA 70 1Q16 Waterborne

Vantage Expansion - Pembina North Dakota 30 2Q16 Pipeline

Morgan's Point Terminal - EPD Baytown, TX 200 3Q16 Waterborne

UTOPIA - KMI Harrison, OH 50 1Q18 Pipeline

Total 440

Ethane Export Capacity Additions (Pipeline & Waterborne)

Source: EIA, Bentek, Company data, Raymond James research



Have We Saturated the Global LPG Market? Will We Tighten N.A. Markets? Will Propane Price To Export?

Plenty of LPG export capacity and PSX coming in 3Q16

• Majority of LPGs heading to Latin America

• Panama Canal Opens Additional Opps. for Asia

• Could see increased butane exports (15% of market?)

• Don’t forget ethane exports heading to Europe for ethylene

production

Y-grade line from Marcellus/Utica could provide additional

supply

• Can a Northeast-to-Gulf Coast Y-grade pipe get built?

• Will Northeast basis differentials improve without it?

Gulf Coast still the best demand market and int’l outlet

0

200

400

600

800

1,000

1,200

1,400

2005

2006

2007

2008

200

9

2010

2011

2012

2013

2014

201

5

2016

2017

2018

Mb

pd

U.S. LPG Export CapacityPotential Propane Exports

Potential Butane Exports

EPD

Targa

SXL/ETP Mariner South/Gulf Coast

OXY - Ingleside

PSX - Freeport

Sage Mid.

Pembria

Source: EIA Data, Waterborne, Raymond James Research, comapny/partnership presentations

Source: Antero Midstream partnership presentations, PIRA

Source: Antero Midstream partnership presentations, PIRA



NGL Pricing Forecast: Pricing Should Firm in 2017 and Hold in 2018

RJ Est. RJ Est. RJ Est. RJ Est. RJ Est. RJ Est. RJ Est. RJ Est. RJ Est. NGL % of

Date Ethane Propane Butane Isobutane Natural Gasoline Nat Gas WTI NGLs (bbls) NGLs (gals) WTI Crude

2016 Avg. $0.19 $0.47 $0.59 $0.65 $0.93 $2.41 $44.52 $18.39 $0.44 41.4%

Current $0.24 $0.66 $0.92 $0.90 $1.19 $2.69 $54.22 $24.91 $0.59 45.9%

1Q17E $0.28 $0.67 $0.91 $0.93 $1.28 $3.50 $60.00 $26.36 $0.63 43.9%

2Q17E $0.26 $0.65 $0.91 $0.92 $1.39 $3.25 $70.00 $26.34 $0.63 37.6%

3Q17E $0.30 $0.62 $0.97 $0.99 $1.49 $3.00 $75.00 $27.69 $0.66 36.9%

4Q17E $0.31 $0.65 $1.11 $1.13 $1.59 $3.25 $75.00 $29.77 $0.71 39.7%

2017 Avg. $0.29 $0.65 $0.98 $0.99 $1.44 $3.25 $70.00 $27.54 $0.66 39.5%

1Q18E $0.34 $0.73 $1.05 $1.06 $1.49 $3.65 $70.00 $30.24 $0.72 43.2%

2Q18E $0.33 $0.72 $0.86 $0.87 $1.28 $3.50 $65.00 $27.44 $0.65 42.2%

3Q18E $0.37 $0.70 $0.86 $0.87 $1.28 $3.35 $65.00 $27.91 $0.66 42.9%

4Q18E $0.38 $0.77 $0.96 $0.98 $1.28 $3.50 $60.00 $29.65 $0.71 49.4%

2018 Avg. $0.36 $0.73 $0.93 $0.95 $1.33 $3.50 $65.00 $28.81 $0.69 44.4%

Long-term $0.35 $0.62 $0.96 $0.98 $1.28 $3.00 $60.00 $27.36 $0.65 45.6%

RAYMOND JAMES PURITY NGL AND COMPOSITE BARREL PRICE FORECAST

Source: Fact Set, Bloomberg, Raymond James estimates.Note: “Current” pricing as of 2/27/17.



Source: INGAA

V. While N-T Capex Slows, L-T Midstream Infrastructure Buildout Opportunities Remain

• Near-term midstream growth capital expenditures have decreased as partnerships “high-grade” their

respective growth programs.

• Many partnerships have worked at minimizing their near-term growth capex requirements due to unaccommodating capital

markets and low producer activity.

• Demand-pull opportunities remain the most valuable.

• While growth capex of the RJ midstream coverage universe is down in 21%/13% y/y in 2016/2017, long-

term opportunities remain.

• INGAA estimates ~$522 billion of additional U.S. infrastructure capital expenditures remain, prompted by expectations of

continued longer-term domestic oil and gas production growth.

• Investments supporting Northeast takeaway capacity and LNG exports are the largest percentage.

• Near-term project set focus of many midstream players continues to trend further downstream within

the value chain.

$11$13

$21

$25

$32$32

$24$23

$21

-

5

10

15

20

25

30

35

2010 2011 2012 2013 2014 2015 2016 2017E 2018E

($ i

n b

illi

on

s)

RJ Midstream Coverage Universe Organic Capex

Source: Company filings, Raymond James research

Historical Average Capex (2010-2016) of ~$23 billion

Organic Capex



VI. Current Valuations: Fair on an Absolute Yield Basis?

• AMZ’s yield ~6.9% as of 2/27/17

• The AMZ’s spread to 10-Year Treasury is currently 520 bps, which is above the ~20-year historical average of 338 bps

• …but what is different now? The 10-Year Treasury Yield.

• 10-Year Treasury Yield rose to 3.75% on 2/8/11 as thoughts of an economic recovery gained momentum and rising

inflation expectations drove yields higher

• 10-Year Treasury Yield averaged more than 3.5% in summer-’09 – today it is just over 2%.

• 10-Year Treasury Yield has since significantly fallen on 1) Fed intervention i.e. its bond-buying program; 2)

Eurozone debt crisis; and 3) the potential for slowing global economy.

• Do Current Valuations:

• 1) Accurately reflect the risk (financing, execution, and integration risk) associated with facilitating CF growth?

• 2) Accurately reflect the full extent of distribution growth?

-100

-50

0

50

100

150

200

250

300

350

400

450

500

550

600

650

700

750

800

Jan

-11

Jul-

11

Jan

-12

Jul-

12

Jan

-13

Jul-

13

Jan

-14

Jul-

14

Jan

-15

Jul-

15

Jan

-16

Jul-

16

Jan

-17

Alerian MLP Index Spread vs. Baa Corporate Bond IndexNormalized Range Avg. Spread bp Spread bp

Basis

Po

ints

(b

p)

Source: Alerian, FactSet, Raymond James research. Priced: 2/27/17 using Friday "end-of-week" data.

Historical AverageSpread: +86 bp

Current Spread:+237 bps

0.0%

2.0%

4.0%

6.0%

8.0%

10.0%

12.0%

14.0%

16.0%

18.0%

Alerian MLP Index Yield 10-Year Treasury YieldRecessions HighlightedMarch 2001 - November 2001November 2007 - July 2009

Crude price collapse has led to Substantial yield spread expansion

since November 2014

2/24/17: 520 bps

Yie

ld

Alerian MLP Index Yield vs. 10-Year Treasury

Priced: 2/27/17 Source: Alerian, Bloomberg



…Or Compelling on a Multiple Basis vs. Historical Precedent?

• MLPs not only appear very attractive based on elevated current yields (both currently

and historically against different asset classes), but also look, at worst “fairly valued”

when using different valuation metrics relative to historic averages

• Lower Price-to-DCF and EV-to-EBITDA multiples would imply greater margin of safety

for MLP investors across the board

• The AMZ is averaging a 7.7x Price-to-DCF multiple as of 2/24/17, which is still a fairly

sizable discount to its medium/long-term historical comps

• The AMZ is averaging an 11.3x EV-to-EBITDA multiple as of 2/24/17, now within close

range of most of its historical comps

• Despite the rally, plenty of opportunities remain!

AMZ (Current vs. Historical Yield Spreads) Current 1-year Prem./Disc. 3-year Prem./Disc. 5-year Prem./Disc.

Yield (%) 6.9% 9.65% 29% 5.82% -18% 5.85% -18%

Spread to Investment Grade (bps) 328 526 N/A 148 N/A 198 N/A

Spread to Treasury (bps) 520 714 N/A 320 N/A 394 N/A

Spread to BAA (bps) 237 442 N/A 84 N/A 83 N/A

Spread to High Yield (bps) 98 107 N/A 25 N/A -124 N/A

RJ Coverage (Current vs. Historical Multiples) Current 1-year Prem./Disc. 3-year Prem./Disc. 5-year Prem./Disc.

EV-to-EBITDA 11.3x 9.5x 20% 11.6x -3% 10.6x 7%

Price-to-DCF 7.7x 5.8x 32% 11.6x -34% 9.1x -15%

Source: Fact Set, Thomson One, Raymond James research



VII. What are the most influential drivers of AMZ yield movements?

Average Daily (1-month) Rolling Correlation

AMZ-HYG AMZ-E&P AMZ-WTI AMZ-REIT EPX-WTI EPX-HYG AMZ-S&P

1-month 0.39 0.78 0.47 -0.01 0.72 0.27 0.32

2-month 0.35 0.78 0.51 0.01 0.73 0.34 0.48

3-month 0.47 0.78 0.56 0.19 0.77 0.42 0.54

6-month 0.59 0.82 0.62 0.27 0.80 0.55 0.58

1-year 0.61 0.79 0.63 0.31 0.77 0.60 0.55

Source: Bloomberg, Raymond James research

-0.4

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9/2

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6

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16

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4/4

/20

16

4/1

9/2

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6

5/4

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16

5/1

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6

6/3

/20

16

6/1

8/2

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6

7/3

/20

16

7/1

8/2

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6

8/2

/20

16

8/1

7/2

01

6

9/1

/20

16

9/1

6/2

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6

10

/1/2

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6

10

/16

/20

16

10

/31

/20

16

11

/15

/20

16

11

/30

/20

16

12

/15

/20

16

12

/30

/20

16

Co

rre

lati

on

% P

erf

orm

an

ce

AMZ-HYG Rolling Correlation vs Performance

HYG AMZ AMZ-HYG

Source: Bloomberg, Thomson, Raymond James Research

-0.40

-0.20

0.00

0.20

0.40

0.60

0.80

1.00

-0.4

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-0.2

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0

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/20

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/4/2

01

6

11

/4/2

01

6

12

/4/2

01

6

1/4

/20

17

Co

rre

lati

on

% P

erf

orm

an

ce

AMZ-WTI Rolling Correlation vs Performance

WTI AMZ AMZ-WTI

Source: Bloomberg, Thomson, Raymond James Research



Where to Invest

Midstream

Favorite C-Corp/Corp GPs:

• Transition/Re-rating: Kinder Morgan, Inc. (KMI), Williams Companies (WMB)

• Offensive: EnLink Midstream LLC (ENLC), Targa Resources Corp (TRGP)

Favorite MLPs:

• Large-cap (+$10 bln): Enterprise Product Partners (EPD), Magellan Midstream Partners (MMP), MPLX LP (MPLX), Energy Transfer Equity (ETE), Williams Partners (WPZ)

• Mid-cap ($2-$10 bln): Antero Midstream LP (AM), Tesoro Logistics LP (TLLP), Valero Energy Partners LP (VLP), Phillips 66 Partners LP (PSXP), Genesis Energy Partners (GEL)

Higher Beta:

• C-Corps and GPs: Plains GP Holdings (PAGP), SemGroup (SEMG)

E&P

• Large-cap: CXO, PXD

• Mid-cap: PE, RSPP

• Small-cap: OAS, SYRG

Oilfield Services

• Pressure Pumping Exposure: HAL, PTEN, SPN

• Other Oil/Upcycle Leverage: NBR, UNT, HCLP

• Niche Buys: NR



Raymond James Coverage: MLP/Midstream Comps

Price Current Market LP/GP Only Coverage Coverage 2015-18 2015-20

Ticker Name 2/28/17 Yield Cap ($ MM) EV ($ MM) 2016E 2017EDist.

CAGR

Dist.

CAGR2016E 2017E 2016E 2017E 2016E 2017E 2016E 2017E 2016E 2017E

LARGE CAP MLPs (> $10 bln)

CQP CHENIERE ENERGY PARTNERS LP $32.28 5.3% $10,905 $10,920 NM 1.82x 1.5% 7.1% 0.0x 0.0x NM NM NM NM 15.0x 8.7x 25.5x 9.8x

EPD ENTERPRISE PRODUCTS PARTNERS LP $28.81 5.6% $61,101 $85,320 1.21x 1.22x 5.2% 5.1% 4.6x 4.3x NM NM 4.6x 4.3x 14.8x 14.0x 16.2x 15.2x

ETP ENERGY TRANSFER PARTNERS LP $38.23 11.0% $20,054 $53,082 0.87x 1.17x NM NM 5.9x 5.0x NM NM 5.9x 5.0x 11.1x 9.2x 13.8x 12.5x

MMP MAGELLAN MIDSTREAM PARTNERS LP $80.15 4.1% $18,257 $22,369 1.25x 1.24x 9.1% 8.6% 3.4x 3.4x NM NM 3.4x 3.4x 19.3x 18.0x 18.4x 17.4x

PAA PLAINS ALL AMERICAN PIPELINE LP $31.08 8.0% $20,575 $32,376 0.92x 1.07x NM NM 5.5x 4.6x NM NM NM NM 20.4x 13.4x 18.7x 13.8x

SEP SPECTRA ENERGY PARTNERS LP $45.55 5.9% $14,348 $21,556 1.16x 1.10x 7.5% 7.0% 3.8x 3.4x NM NM NM NM 13.9x 14.1x 13.9x 13.0x

WPZ WILLIAMS PARTNERS LP $40.03 8.5% $23,855 $42,396 1.01x 1.31x NM NM 4.2x 4.0x NM NM NM NM 10.3x 12.0x 11.3x 12.3x

LARGE CAP MLPs (> $10 bln) AVERAGE 6.9% $24,156 $38,288 1.07x 1.27x 5.8% 7.0% 3.9x 3.5x NM NM 4.6x 4.3x 15.0x 12.8x 16.8x 13.4x

S-MID (SMALL & MID) CAP MLPs (< $10 bln)

Gathering & Processing Midstream/MLPs

AM ANTERO MIDSTREAM PARTNERS LP $35.07 2.9% $6,186 $7,055 1.75x 1.47x 28.6% 28.3% 2.2x 2.2x NM NM NM NM 18.7x 16.6x 18.8x 15.6x

BWP BOARDWALK PIPELINE PARTNERS LP $18.28 2.2% $4,575 $8,246 4.84x 5.00x 0.0% 18.1% 4.6x 4.8x NM NM NM NM 9.3x 9.0x 10.4x 10.4x

CEQP CRESTWOOD EQUITY PARTNERS LP $26.45 9.1% $1,838 $3,951 1.81x 1.37x NM NM 3.4x 4.3x NM NM 3.4x 4.3x 6.0x 8.1x 8.7x 10.5x

ENLK ENLINK MIDSTREAM LP $18.90 8.3% $6,299 $10,306 1.03x 1.09x 1.4% 2.3% 4.2x 4.2x NM NM NM NM 11.5x 10.9x 14.4x 13.4x

PTXP PENNTEX MIDSTREAM PARTNERS LP $15.89 7.2% $644 $800 1.35x 1.27x 32.7% 23.3% 2.3x 3.7x NM NM NM NM 10.2x 9.8x 11.6x 12.6x

SXE SOUTHCROSS ENERGY PARTNERS LP $2.84 0.0% $138 $677 NA NA NM NM 8.1x 6.8x NM NM NM NM 4.7x 3.7x 10.1x 8.5x

Gathering & Processing Midstream/MLPs AVERAGE 4.9% $3,280 $5,172 2.16x 2.04x 15.7% 18.0% 4.1x 4.3x NM NM 3.4x 4.3x 10.1x 9.7x 12.3x 11.8x

Diversified Midstream MLPs

CLMT CALUMET SPECIALTY PRODUCTS LP $3.85 0.0% $296 $2,289 NM NM NM NM 14.5x 8.1x NM NM NM NM NM 5.8x 16.7x 9.3x

GEL GENESIS ENERGY PARTNERS LP $34.78 8.0% $4,105 $7,189 1.19x 1.18x 7.0% 6.2% 5.8x 5.7x NM NM NM NM 10.3x 10.1x 13.5x 12.9x

MMLP MARTIN MIDSTREAM PARTNERS LP $18.65 14.1% $659 $1,467 1.11x 1.30x NM NM 4.6x 4.9x NM NM NM NM 6.3x 7.1x 8.8x 39.5x

NGL NGL ENERGY PARTNERS LP $23.43 6.9% $2,556 $5,712 1.67x 1.61x NM 2.5% 6.3x 5.1x NM NM NM NM 7.7x 6.4x 11.6x 9.8x

NS NUSTAR ENERGY LP $53.69 8.2% $4,182 $7,246 1.05x 1.07x 0.6% 1.9% 5.3x 4.0x NM NM NM NM 11.6x 11.4x 13.7x 12.1x

Diversified Midstream MLPs AVERAGE 7.4% $2,360 $4,781 1.26x 1.29x 3.8% 3.6% 7.3x 5.6x NM NM NM NM 9.0x 8.1x 12.8x 16.7x

Fuels Distributors / Terminals / Retail MLPs

CAPL CROSSAMERICA PARTNERS LP $26.71 9.0% $892 $1,412 0.97x 1.03x 3.0% 2.5% 5.0x 4.9x NM NM NM NM 11.5x 10.5x 14.2x 13.5x

GLP GLOBAL PARTNERS LP $19.98 9.3% $670 $1,839 1.14x 1.02x NM NM 6.2x 6.2x NM NM NM NM 9.4x 10.5x 9.7x 9.8x

SRLP SPRAGUE RESOURCES LP $27.20 8.2% $580 $1,000 1.76x 1.64x 10.9% 9.9% 3.6x 3.2x NM NM NM NM 6.7x 6.3x 8.8x 8.3x

SUN SUNOCO LP $28.03 11.7% $2,831 $2,836 1.02x 1.03x 5.9% 3.9% 0.0x 0.0x NM NM NM NM 7.0x 6.6x 4.9x 4.6x

Fuels Distributors / Terminals / Retail MLPs AVERAGE 9.6% $1,243 $1,772 1.22x 1.18x 6.6% 5.4% 3.7x 3.6x NM NM NM NM 8.6x 8.5x 9.4x 9.0x

S-MID (SMALL & MID) CAP MLPs (< $10 bln) AVERAGE 7.0% $2,430 $4,135 1.59x 1.54x 10.0% 9.9% 5.1x 4.5x NM NM 3.4x 4.3x 9.3x 8.8x 11.7x 12.7x

Source: Raymond James Research; Thomson

RAYMOND JAMES ENERGY RESEARCH - MLPs / MIDSTREAM SUPPLIERS COMPARISON TABLESLP-only Debt /

EBITDA

GP-only Debt /

EBITDA

Consolidated Debt

/ EBITDAPrice / DCF LP-only EV / EBITDA



Raymond James Coverage: MLP/Midstream Comps

Price Current Market LP/GP Only Coverage Coverage 2015-18 2015-20

Ticker Name 2/28/17 Yield Cap ($ MM) EV ($ MM) 2016E 2017EDist.

CAGR

Dist.

CAGR2016E 2017E 2016E 2017E 2016E 2017E 2016E 2017E 2016E 2017E 2016E 2017E 2016E 2017E

REFINING LOGISTICS MLPs

DKL DELEK LOGISTICS PARTNERS LP $32.60 6.4% $795 $1,180 1.27x 1.11x 8.5% 6.7% 3.9x 3.8x NM NM NM NM 11.1x 9.5x 13.9x 12.4x NM NM NM NM

HEP HOLLY ENERGY PARTNERS LP $36.89 6.4% $2,219 $3,427 1.09x 1.09x 7.7% 7.0% 4.3x 4.1x NM NM NM NM 13.8x 12.7x 15.6x 15.0x NM NM NM NM

MPLX MPLX LP $38.28 5.4% $13,751 $19,045 1.23x 1.14x 12.3% 9.8% 3.0x 4.0x NM NM NM NM 14.3x 13.3x 15.7x 16.1x NM NM NM NM

PBFX PBF LOGISTICS LP $20.90 8.3% $872 $1,397 1.28x 1.28x 11.4% 9.7% 4.3x 4.1x NM NM NM NM 9.0x 8.3x 11.9x 10.8x NM NM NM NM

PSXP PHILLIPS 66 PARTNERS LP $56.35 3.7% $6,009 $8,504 1.29x 1.35x 23.3% 19.8% 5.6x 4.7x NM NM NM NM 19.2x 14.5x 24.0x 17.2x NM NM NM NM

TLLP TESORO LOGISTICS LP $59.00 5.8% $6,073 $9,365 1.04x 1.30x 14.0% 12.1% 4.7x 4.4x NM NM NM NM 15.4x 10.2x 17.1x 13.2x NM NM NM NM

VLP VALERO ENERGY PARTNERS LP $50.26 3.0% $3,385 $4,214 1.94x 1.78x 23.3% 20.3% 3.2x 3.8x NM NM NM NM 15.7x 13.0x 17.7x 15.5x NM NM NM NM

WNRL WESTERN REFINING LOGISTICS LP $24.05 6.9% $1,464 $1,774 1.03x 1.10x 12.5% 11.0% 2.7x 3.1x NM NM NM NM 14.5x 10.7x 16.0x 13.5x NM NM NM NM

REFINING LOGISTICS MLPs AVERAGE 5.7% $4,321 $6,113 1.27x 1.27x 14.1% 12.1% 4.0x 4.0x NM NM NM NM 14.1x 11.5x 16.5x 14.2x NM NM NM NM

RETAIL PROPANE DISTRIBUTOR MLPs

APU AMERIGAS PARTNERS LP $48.64 7.7% $4,524 $7,071 0.82x 1.06x 2.3% 2.1% 4.7x 3.5x NM NM NM NM 16.5x 11.9x 14.3x 11.3x NM NM NM NM

FGP FERRELLGAS PARTNERS LP $6.37 32.2% $628 $2,691 0.98x 4.17x NM NM 6.0x 6.3x NM NM NM NM 3.2x 3.8x 7.9x 8.3x NM NM NM NM

SPH SUBURBAN PROPANE PARTNERS LP $27.40 13.0% $1,672 $2,911 0.59x 0.96x 0.1% 0.2% 5.6x 4.0x NM NM NM NM 13.1x 8.0x 13.1x 9.5x NM NM NM NM

RETAIL PROPANE DISTRIBUTOR MLPs AVERAGE 17.6% $2,274 $4,225 0.79x 2.06x 1.2% 1.2% 5.4x 4.6x NM NM NM NM 10.9x 7.9x 11.7x 9.7x NM NM NM NM

MARITIME TRANSPORTATION MLPs

CPLP CAPITAL PRODUCT PARTNERS LP $3.41 8.9% $408 $997 2.63x 2.39x NM NM 3.6x 3.5x NM NM NM NM 3.4x 3.7x 6.2x 6.2x NM NM NM NM

GMLP GOLAR LNG PARTNERS LP $23.55 9.8% $1,697 $1,697 1.34x 1.38x 0.9% 1.8% NM NM NM NM NM NM 8.7x 8.4x 4.8x 4.5x NM NM NM NM

KNOP KNOT OFFSHORE PARTNERS LP $22.20 9.4% $615 $615 1.25x 1.30x 2.5% 2.5% NM NM NM NM NM NM 8.4x 7.9x 4.6x NM NM NM NM NM

TGP TEEKAY LNG PARTNERS LP $18.55 3.0% $1,477 $3,712 5.35x 5.94x NM NM 4.6x 5.5x NM NM NM NM 6.1x 5.5x 7.6x 8.3x NM NM NM NM

TOO TEEKAY OFFSHORE PARTNERS LP $5.48 8.0% $1,930 $5,079 3.44x 5.17x NM NM 5.6x 5.4x NM NM NM NM 3.3x 2.4x 9.1x 8.2x NM NM NM NM

MARITIME TRANSPORTATION MLPs AVERAGE 7.8% $1,225 $2,420 2.80x 3.24x 1.7% 2.2% 4.6x 4.8x NM NM NM NM 6.0x 5.6x 6.5x 6.8x NM NM NM NM

MIDSTREAM C-CORPs

KMI KINDER MORGAN INC $21.74 2.3% $48,458 $89,388 3.88x 4.05x NM 4.0% 5.6x 5.7x NM NM 5.6x 5.7x 11.2x 10.7x 12.3x 12.4x NM NM 12.3x 12.4x

PAGP PLAINS GP HOLDINGS $31.94 7.8% $21,146 $32,947 0.92x 1.07x NM NM 5.5x 4.6x NM NM 5.5x 4.6x 20.9x 13.8x 19.1x 14.0x NM NM 19.1x 14.0x

SEMG SEMGROUP CORP $40.00 4.5% $2,085 $3,100 NM NM 5.6% 6.4% 3.6x 4.7x NM NM 3.6x 4.7x NM NM 11.0x 13.7x NM NM 11.0x 13.7x

TRGP TARGA RESOURCES CORP $58.58 6.2% $9,801 $14,855 1.10x 1.08x 4.2% 5.4% 4.6x 4.1x NM NM 4.6x 4.1x 14.3x 14.5x 14.0x 13.2x NM NM 14.0x 13.2x

MIDSTREAM C-CORPs AVERAGE 5.2% $20,373 $35,072 1.96x 2.07x 4.9% 5.3% 4.8x 4.8x NM NM 4.8x 4.8x 15.5x 13.0x 14.1x 13.4x NM NM 14.1x 13.4x

GENERAL PARTNERS

MLP GPs

ETE ENERGY TRANSFER EQUITY LP $19.05 6.0% $19,924 $27,751 1.24x 1.05x NM NM NM NM 4.2x 4.6x 5.7x 4.9x 16.5x 19.4x NM NM 18.3x 20.6x 14.0x 13.6x

NSH NUSTAR GP HOLDINGS LLC $30.00 7.3% $1,288 $1,288 1.00x 1.17x 2.2% 3.3% NM NM NM NM NM NM 13.7x 11.8x NM NM NM NM NM NM

MLP GPs AVERAGE 6.6% $10,606 $14,519 1.12x 1.11x 2.2% 3.3% NM NM 4.2x 4.6x 5.7x 4.9x 15.1x 15.6x NM NM 18.3x 20.6x 14.0x 13.6x

C-CORP GPs

ENLC ENLINK MIDSTREAM LLC $19.05 5.4% $3,434 $4,173 1.08x 1.17x 6.0% 9.7% NM NM -0.1x 0.0x 4.2x 4.1x 17.0x 15.8x NM NM 20.3x 19.7x 16.3x 15.1x

LNG CHENIERE ENERGY INC $46.69 0.0% $10,681 NM NM NM NM NM NM NM NM NM NM NM NM NM NM NM NM NM NM NM

SE SPECTRA ENERGY CORP $41.12 3.9% $28,841 $37,246 1.23x 1.11x 8.7% 8.4% NM NM 4.3x 4.9x 5.5x 5.7x 20.7x 21.0x NM NM 19.3x 18.4x 16.6x 15.9x

TK TEEKAY CORPORATION $10.15 2.2% $863 NM 1.56x 1.35x NM NM NM NM NM NM NM NM 25.2x 22.7x NM NM 16.8x 11.6x NM NM

WMB WILLIAMS COMPANIES INC $28.22 6.0% $21,191 $25,897 1.44x 1.33x NM NM NM NM 2.3x 2.6x 5.2x 4.9x 11.6x 17.5x NM NM 12.5x 16.1x 12.3x 12.1x

C-CORP GPs AVERAGE 3.5% $13,002 $22,439 1.33x 1.24x 7.4% 9.1% NM NM 2.2x 2.5x 5.0x 4.9x 18.6x 19.2x NM NM 17.2x 16.5x 15.1x 14.4x

GENERAL PARTNERS AVERAGE 4.4% $12,318 $19,271 1.26x 1.20x 5.7% 7.2% NM NM 2.7x 3.0x 5.2x 4.9x 17.5x 18.0x NM NM 17.4x 17.3x 14.8x 14.2x

Source: Raymond James Research; Thomson

RAYMOND JAMES ENERGY RESEARCH - MLPs / MIDSTREAM SUPPLIERS COMPARISON TABLESLP-only Debt /

EBITDA

GP-only Debt /

EBITDA

Consolidated Debt

/ EBITDAPrice / DCF LP-only EV / EBITDA

GP-only EV /

EBITDA

Consolidated EV /

EBITDA



IX. Risks Include (but are not Limited to):

• Distributions/Dividends are not guaranteed

• Partnership and Company-specific risks do exist– GP/IDR burden on underlying LP cost of equity capital can hurt ROE/ROIC metrics

• Commodity price risk – Direct: some gas processing contracts– Indirect: volumetric risk if producer well-head economics are challenged

• Capital markets risk

• Regulatory/Structural (ie: Tax Reform) risk

• Interest rate risk

• Liquidity Risk

• Capital Allocation/Balance sheet risk



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