Natural Gas Don't Bet Against Innovation: Sub-$3 Is the ...csinvesting.org/wp-content/uploads/2017/07/Natural... · Don't Bet Against Innovation: Sub-$3 Is the New Normal We see structural

MMarch 28, 2017 04:03 AM GMT

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Natural Gas

Don't Bet Against Innovation: Sub-$3 Is the New NormalWe see structural pressure on LT gas prices from oil, productivity

improvements & weakening power demand. We are reducing our 2017-18gas price forecast, and cutting our LT outlook by 27% to $2.75. The cross-industry implications drive several price target and rating changes across E&Ps, Power, Coal, Rails, Chemicals & LNG Exporters.

M

MORGAN STANLEY & CO. LLC

DEVIN MCDERMOTTEQUITY ANALYST

+1212 761-1125

[email protected]

Contributors


DREW VENKER, CFAEQUITY ANALYST

+1212 761-3729

[email protected]


STEPHEN C BYRDEQUITY ANALYST

+1212 761-3865

[email protected]


EVAN L KURTZ, CFAEQUITY ANALYST

+1212 761-7583

[email protected]


EVAN CALIOEQUITY ANALYST

+1212 761-6472

[email protected]


RAVI SHANKEREQUITY ANALYST

+1212 761-6350

[email protected]


VINCENT ANDREWSEQUITY ANALYST

+1212 761-3293

[email protected]


TOM ABRAMSEQUITY ANALYST

+1 212 296-8112

[email protected]


FOTIS GIANNAKOULISEQUITY ANALYST

+1 212 761-3026

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KEN BEYERRESEARCH ASSOCIATE

+1 212 761-8763

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M

4 Don't Bet Against Innovation - Sub-$3 is the New Normal

6 Key Takeaways

12 Natural Gas: Lower for Longer -Sub - $3 is the New Normal

21 Long-Term Gas: Cutting Forecast to $2.75

23 Coal: Cutting Longer-Term Demand Estimates on Lower Gas Deck and Growing Renewables

34 Diversified Utilities and IPPs: Pockets of Opportunity in a Low-Gas World

35 Merchant Power Stock Implications

37 Midstream Implications

38 Nuclear Support More Likely in a Low-Gas Environment

39 Chemicals

45 Rails: Coal Window of Opportunity Narrowing

48 Valuation Methodology and Risk

Contents

M

$2-3/MMbtu natural gas, not $3-4, is the new normal. Innovationacross the Energy sector has structurally changed the natural gasmarket, and creates several headwinds for prices: a precipitousdecline in breakevens for unconventional US oil plays, substantialcapital productivity improvements in natural gas extraction, andpower sector demand erosion from renewables and normalizinghydrology in the western US. As a result, the window for the gas pricebull case to play out is quickly closing. We are reducing our 2017-18price forecast, and cutting our long-term Henry Hub expectation by27% to $2.75/MMbtu, with narrowing differentials and $2.25-2.50prices across Appalachia. While the gas market remains tight in theshort term, our revised forecast is now below the forward curve andhas substantial cross-industry implications, negatively affecting gas-levered E&Ps, Power, Coal & Rails, while benefitting Midstream, LNGexport margins & Chemicals. Three key themes drive our new naturalgas views:

1. Oil's strength is gas's weakness: 60% of new demand through2020 can be met with associated gas. Unconventional shalewell costs have fallen while recoveries have moved higher, drivinga precipitous 60-70% decline in breakeven prices for key oil playsover the past few years, notably in the Permian. Activity levels areincreasing in response to improved economics and a strongerglobal oil market, setting up to create a glut of associated gas andpotentially widening local basis in the Gulf Coast. Oil prices are akey risk to our call, as we see the two commodities as negativelycorrelated over the next few years. Our estimates incorporate$60/bbl WTI oil by 2018, in line with Morgan Stanley's construct-ive oil forecast, and flat prices thereafter.

Natural Gas

Don't Bet Against Innovation: Sub-$3 Is the New NormalWe see structural pressure on LT gas prices from oil, productivity

improvements & weakening power demand. We are reducing our 2017-18gas price forecast, and cutting our LT outlook by 27% to $2.75. The cross-industry implications drive several price target and rating changes across E&Ps, Power, Coal, Rails, Chemicals & LNG Exporters.

2. Natural gas breakevens continue to fall. Gas productivityimprovements have also taken hold, with breakevens across sev-eral key plays now well below $3/MMbtu, including the Haynes-ville. Despite delays, by 2018 the pipeline buildout will begin tounleash more low-cost supply from Appalachia, narrowing differ-entials in the region and pressuring Henry Hub prices.

3. Power demand: mounting challenges. Gas demand from powergeneration remains a key balancing factor for the gas market. Inthe short term (2017), the end of drought conditions in the west-ern US should drive strong hydropower production, displacinggas. Longer term, total electricity demand is not growing andrenewables continue to take share from gas, offsetting much ofthe benefit from coal retirements.

Coal: Lower gas set to further pressure demand and prices. Aftera one-year increase in coal consumption in 2017 due to sequentiallyhigher gas prices, we expect coal’s structural decline to resume. Weare cutting our 2017 coal burn forecast by ~4%, and now see only amodest year-over-year improvement, with a majority of gains lost by2018 due to ongoing competition from gas and growing renewables.This dynamic also pressures rail volumes, particularly in the east.

Our revised forecast is now incorporated in our equity valua-tions, driving meaningful price target changes across E&P and Powerstocks and resulting in downgrades of Exelon (EXC) and Gulfport(GPOR). We are also reducing price targets for the rails (Union Pacificand Norfolk Southern) by 2-3%, and continue to prefer the west overeast. On the positive side, we are increasing our price target for LNGexporter Cheniere to $55 (from $50), and see it as a key beneficiary

https://ny.matrix.ms.com/eqr/article/webapp/b049c96e-0422-11e7-a7dd-658d90c42708?ch=rpint


Mof lower US gas prices. Chemicals companies are also positioned tobenefit from low US gas prices, while midstream is positively leveredto the supply and processing growth we forecast.

Most gas-exposed equities have underperformed significantlyYTD, and technical measures now place them in oversold territory.This creates near-term risk to our bearish call, and we could see theequities rebound, particularly if oil prices do not recover, driving gasfundamentals to improve in 2H17. Among E&Ps, we see less attract-ive risk-reward for gas exposure than for oil, and our call is about rela-tive underperformance of gas within energy, not significant absolutedownside. For Utilities, the reduction in our long-term gas forecast

Exhibit 1:Summary of Price Target Changes

Diversified

Utilities / IPPs Old PT

Price

Change New PT % Change % Upside

NRG $25 ($5) $20 -20% 10%

DYN $18 ($3) $15 -17% 105%

EXC $40 ($3) $37 -8% 2%

D $82 ($3) $79 -4% 1%

CPN $13 ($2) $11 -15% 2%

PEG $51 ($2) $49 -4% 9%

FE $42 ($2) $40 -5% 28%

NEE $158 ($2) $156 -1% 17%

E&Ps

EQT $86 ($27) $59 -31% 3%

GPOR $29 ($16) $13 -55% -20%

RRC $48 ($15) $33 -31% 19%

AR $37 ($9) $28 -24% 24%

SWN $10 ($3) $7 -30% -7%

ECR $4 ($1.60) $2.40 -40% 1%

COG $27 ($1) $26 -4% 12%

Rails

NSC $74 ($2) $72 -3% -35%

UNP $99 ($2) $97 -2% -7%

LNG Export

LNG $50 $5 $55 10% 22%

Natural Gas

2017 $3.50 ($0.40) $3.10 -11% -3%

2018 $3.20 ($0.30) $2.90 -9% -5%

Long-Term $3.75 ($1.00) $2.75 -27% N/ANote: Natural Gas prices cited for Henry Hub in $/MMbtu

Devin McDermott is the lead US Gas & Power commodity strategist and an analyst on the Power, Utilities & Clean Tech equity research team.With this report he is formally assuming responsibility for Morgan Stanley's natural gas price forecasts.

leads to PT reductions across our merchant power coverage, but westill see valuation dislocations for some in the group, robust cashflow generation, and a constructive setup overall for merchant pow-er-related equities in 2017.

6

MKey Takeaways

Exhibit2:Structural Pressure Should Keep Natural Gas Prices Low, DespiteDemand

Source: Morgan Stanley Research, Bloomberg

Natural Gas: Lower for Longer - Sub $3 Is the New Normal

Pricing pressure from oil, productivity improvements & powerdemand. For years the "bull case" for natural gas has been anchoredin structural demand growth in the later part of this decade. Thatstructural growth has arrived, and remains intact despite the nega-tive impacts of yet another very mild winter. However, innovationacross the energy sector has created several headwinds that shouldkeep prices low. The most notable of these is a precipitous decline inbreakevens for unconventional US oil plays. We expect improved oileconomics, particularly in the gas-heavy sections of the Permianbasin, to drive rapid growth in associated gas production, regardlessof how low gas prices fall. On the gas side, capital productivityimprovements have also taken hold, with breakevens across severalkey plays now well below $3/MMbtu. Lastly, in power, the end ofdrought conditions in the western US will allow hydro to displacegas. Longer term, declining electricity demand and growth in renewa-bles gradually erode gas and coal generation needs. As a result, thewindow for the gas price bull case to play out is quickly closing. Weare reducing our 2017-18 and long-term Henry Hub gas price fore-casts, with a refreshed outlook driven by three key themes:

1. Oil: improving shale economics coupled with a stronger globaloil market is negative for gas. Over the last several years, innova-tion has driven a substantial reduction in unconventional shale wellcosts while recoveries have moved higher. The result has been a pre-cipitous 60-70% decline in breakeven prices for key shale plays. Themost notable declines have been in the Permian in Texas, where20-33% (lower in the Midland, higher in the Delaware) of the energyoutput is natural gas. In response to improved economics, rig countshave increased by 200, to 310, since mid-2016, with a shift into thegas-heavy Delaware. The result is substantial growth in associatedgas, regardless of how low gas prices fall, plus potential periodic wid-ening of local price differentials (basis) in the Gulf Coast region. Infact, by 2020 we expect total associated gas to grow by ~7.5 Bcf/day,led by the Permian and Oklahoma (STACK). This gas is roughly equiv-alent to all incremental planned LNG export projects, and is geo-graphically close to demand growth in the US Gulf Coast. Our esti-mates incorporate $60/bbl WTI oil by 2018, in line with Morgan Stan-ley's constructive oil forecast, and flat prices thereafter. That said, oilprices are a key risk to our call, as we see the two commodities asnegatively correlated over the next few years.

Exhibit 3:Lower Well Costs...

$7.1 $7.7 $7.7

$6.6

$5.7

$0.0

$1.0

$2.0

$3.0

$4.0

$5.0

$6.0

$7.0

$8.0

$9.0

2012 2013 2014 2015 2016

Delaware Well Cost (Million USD)

Source: Rystad Energy

Exhibit 4:…Coupled with Higher Recoveries

-

20

40

60

80

100

120

140

160

0 2 4 6 8 10 12 14 16 18 20 22 24 26 28 30 32 34 36

Barr

els

of

Oil

(000's

)

Months

Average Delaware Well Production

2012 2013 2014 2015 2016

Source: DrillingInfo


MORGAN STANLEY RESEARCH 7

MExhibit 5:Have Driven 60-70% Declines in Permian Oil Breakevens...


Exhibit 6:...Supporting Rapid Growth in Associated Gas, Regardless of How LowGas Prices Fall

0

1,000

2,000

3,000

4,000

5,000

6,000

7,000

8,000

9,000

2014 2015 2016 2017e 2018e 2019e 2020e

Permian Oil & Gas Production Oil Production (mbld)Associated Gas (mmcf/d)

Source: Morgan Stanley Research, Company Data

2. Capital productivity improvements have meaningfullyreduced natural gas supply costs. While recent gains have not beenas impressive as oil, they are still significant. Shale breakevens havecontinued to trend lower, supporting production growth at lowerprices. Even non-Appalachian plays have made significant gains, per-haps most notably the Haynesville (Texas & Louisiana), where break-evens now sit comfortably below $3/MMBtu. As a result, gas rigcounts have nearly doubled from the lows seen in mid-2016. In theHaynesville, the rig count has tripled since September, and now sitsat 35. Separately, substantial pipeline expansions in 2018 will sup-port further growth out of low-cost basins in Appalachia, wherebreakevens range from $1.50 to $2.50/MMBtu. In aggregate, we fore-cast a reacceleration of dry-gas production growth on top of the glutof supply from associated gas, more than adequate to meet totaldemand growth between now and 2020 without higher prices.

Exhibit 7:Gas Breakevens in Key Plays Are Now Comfortably Below $2.75

$1.50

$2.17 $2.28 $2.40

$2.83

$3.42

$0.00$0.50$1.00$1.50$2.00$2.50$3.00$3.50$4.00

Terryville -Upper Red

SWPA -Marcellus

NEPA -Marcellus

Haynesville Ohio Utica -Dry Gas

Fayetteville

Henry Hub Breakevens Assumes 20% IRR & $60/Bbl WTI

Source: Morgan Stanley Research

Exhibit 8:Gas Rig Counts Have Nearly Doubled Since Mid-2016

-

20

40

60

80

100

120

140

160

Jan-1

6

Feb-1

6

Mar-

16

Apr-

16

May-1

6

Jun-1

6

Jul-16

Aug-1

6

Sep-1

6

Oct-

16

Nov-1

6

Dec-1

6

Jan-1

7

Feb-1

7

Mar-

17

Gas Rig Count

Other Utica Marcellus Haynesville

Source: Bloomberg, Morgan Stanley Research

3. Power demand: mounting challenges. Gas demand from powergeneration remains a key balancing factor for the gas market. Goingforward, total demand for electricity is not growing in the US, and infact is likely to modestly decline. Our analysis of power demand indi-cates total US generation is likely to decline at a 0.3% CAGR 2015-25due to energy efficiency, LED lighting, and rooftop solar. Gas is com-peting alongside coal and renewables for a shrinking pie of demand.In the short term (2017), the end of drought conditions in the westernUS should drive strong hydropower production, displacing gas. Afteryears of drought, wet winter conditions have driven substantialincreases in reservoir levels across much of the western US. Further-more, snowpack in California's Sierra Nevada mountains has nowreached 180% of normal, creating a steady supply of additional wateras melting occurs into the spring and summer. This will result instronger hydropower production, which we estimate will displace

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8

MExhibit 9:We Forecast a 3.5 Bcf/d Reduction in Power Sector Gas Burn Summer-over-Summer in 2017...


Exhibit 11:Our 2018 Price Outlook Is Sensitive to Oil Prices

1.3 2.5

$3.2

$2.9

$2.7

$2.8

$2.9

$3.0

$3.1

$3.2

$3.3

-

0.5

1.0

1.5

2.0

2.5

3.0

2018 ($50/bbl WTI) 2018 Base ($60/bbl WTI)

Left: YoY Associated Gas Growth in 2018 (Bcf/d)

YoY Associated Gas Growth (Bcf/d)Gas Price Needed to Balance Market ($/MMbtu)Forward Curve

Right: 2018 Gas Price ($/MMbtu)

Source: Morgan Stanley Research. Henry Hub prices shown, forward curve as of 3/24/17.

Exhibit 10:...While Longer-Term Total Demand for Electricity Is Set to Decline


~0.4 Bcf/day of gas generation on average April-October. Longerterm, renewables continue to take share from gas, offsetting muchof the benefit from coal retirements. In fact, the lost gas demandfrom renewables year-over-year in 2017 (0.7 Bcf/d) is equal to thecumulative benefit from all announced coal retirements 2017-20.Lastly, we see downside to coal prices which could result in the needfor lower gas prices to incentivize fuel switching (as coal becomesmore competitive).

The Result:

Lower prices for longer: sub-$3 gas is the new normal. While thegas market remains tighter than recent history through late 2017, thisdynamic is likely to be short-lived. Substantial growth in associatedgas, led by the Permian Basin, will create a glut of low-cost supplynear key demand growth regions in the US Gulf Coast. Beginning in2018, pipeline buildout should unleash low-cost supply from Appala-chia, narrowing differentials and pressuring Henry Hub prices. Thebiggest risk to our outlook, beyond weather variability (we assumenormal weather), is further weakness in the global oil market, as itcould significantly reduce associated gas growth. Short-term infra-structure limitations delivering associated gas from oil plays todemand centers is also a risk, and could drive a periodic expansion inGulf Coast basis differentials over the next few years. That said, per-mitting new pipelines is relatively easy in the region, allowing anydelivery constraints to be quickly addressed. We are cutting our near-and long-term gas price forecasts:

l 2017: Yet another year of mild winter weather has loosened thesupply-demand outlook for the balance of the year, eroding muchof the near-term bull case for natural gas. We forecast averageHenry Hub prices of $3.10-3.15/MMBtu for the balance of the yearwill be adequate to refill inventories. That said, the marketremains much tighter than recent history. If rebalancing of theglobal oil market (and a resulting improvement in oil prices)doesn’t begin to occur, we believe gas prices could instead see ashort-term rally into the mid- to high-$3 range by year-end. Weexpect any strength would trigger a meaningful supply responseand be short-lived.

l 2018: By early 2018, pipeline expansions and an acceleration ofassociated gas production allows for low-cost supply to meetgrowth in demand. While early 2018 has the potential for high pri-ces if additional infrastructure delays occur, our latest forecastcalls for adequate pipeline expansion and production growth byJanuary/February. We are cutting our forecast to $2.90, andexpect prices to break into the $2.70-2.80/MMbtu by 2Q18,implying further downside to the current forward curve.


Ml Long Term: We are reducing our long-term natural gas price fore-

cast by roughly 27%, from $3.75 to $2.75. The meaningful reduc-tion in our outlook is driven by improved unconventional shalegas & oil economics and a substantial increase in Gulf Coast asso-ciated gas, which we now forecast will meet 60% of total demandgrowth through 2020. Net of associated gas, incremental supplyneeds are very modest and can be met with low cost Haynesvilleand Marcellus/Utica production without higher prices. Ourrevised outlook assumes $2.25-2.50 prices across Appalachia.Higher levels of Gulf Coast production reduces the demand pullout of the region, allowing basis differentials to stabilize at a dis-count to firm transport costs. Our revised forecast is below theforward curve and what appears to be priced into many gas-ex-posed equities.

Exhibit 12:Associated Gas Meets ~60% of Demand Growth Through 2020...

-5.9 -2.3 5.1 12.6

+0.7

2016-20 DemandGrowth (Bcf/d)

Net SupplyGrowth Needed

(Bcf/d)

Other AssociatedDeclines

PermianAssociated Gas

SCOOP/STACKAssociated Gas

Source: Morgan Stanley Research. Assumes flat $60/bbl WTI prices 2018-20.

Exhibit 13:...but Oil Prices Remain a Key Variable

0.0

0.5

1.0

1.5

2.0

2.5

3.0

2017 2018 2019 2020

Th

ou

san

ds

Year-over-Year Assoicated Gas Growth (Bcf/d)

$50/bbl $60/bbl (Base Case) $77/bbl

Source: Morgan Stanley Research. Note: The $50 and $60 case assume flat prices 2018-20, while the $77 case assumes prices gradually rise to $77 by 2020.

Coal

Exhibit 14:Coal Demand Remains Sensitive to Natural Gas Prices

500

550

600

650

700

750

800

Gas Price ($/mmBtu)

2017 Power Sector Coal Burn (Mil Tons)

PRB / Western

Coals

Eastern /

Appalachian Coals


Coal’s structural decline expected to continue. We are cutting our2017 coal burn forecast by ~28mnt, and now forecast only a 4% YoYincrease in coal generation for the year, driven by higher gas prices.The majority of gains will be lost by 2018e due to ongoing competi-tion from gas and growing renewables. Exports are unlikely to be asource of new demand due to challenged economics and state levelpermitting issues. Our fundamental analysis of power generationeconomics shows that longer-term coal simply cannot compete withnatural gas or renewables (even on an unsubsidized basis), regard-less of any changes made to environmental regulations. As a result,after a one-year increase in coal consumption in 2017e due to sequen-tially higher gas prices, we expect coal’s structural decline to resume,and see natural gas as a relative winner. Our updated supply demandestimates and price forecasts are in Exhibit 15 and Exhibit 16 ,respectively.

10

MExhibit 15:We Are Cutting Our 2017 Power Sector Coal Burn Forecast by 28mnt,but Increasing Production by 14 mnt Based on YTD Trends

2014 2015 2016e 2017e 2018e

Production (mt)

PRB 440 418 330 370 370

CAPP 116 90 67 77 58

NAPP 135 118 106 125 110

ILB 137 124 101 110 110

Total, with others 1,000 896 739 830 788

Prior

PRB 330 370 370

CAPP 70 73 58

NAPP 107 115 110

ILB 103 110 110

Total, with others 750 816 788

Demand (mt)

Electric Power Burn 849 737 675 704 685

YE Utility Inventory 65 97 86 85 81

Prior

Electric Power Burn 672 732 694

YE Utility Inventory 94 70 63

Generation (TWh)

Total 4,094 4,078 4,078 4,075 4,088

Coal-Fired 1,586 1,350 1,242 1,295 1,260

Gas-Fired 1,127 1,333 1,381 1,292 1,283

Renewables 295 319 361 406 458

Prior

Total 4,059 4,073 4,086

Coal-Fired 1,223 1,335 1,266

Gas-Fired 1,395 1,243 1,270

Renewables 358 412 461

Source: EIA, Morgan Stanley Research Estimates. Note: CAPP refers to Central Appalachia, NAPP to Northern Appalachia, PRB to Powder River Basin, and ILB to Illinois Basin

Exhibit 16:We Are Reducing Our LT Price Forecasts for CAPP, NAPP, and ILB, Dueto Lower Gas Prices

2014 2015 2016 2017e 2018e LTe

Coal Pricing ($/t)

PRB 8800 0.8# $12 $11 $9 $10 $10 $12

CAPP 12500 1.6# $59 $51 $42 $46 $48 $46

NAPP 13000 3.0# $66 $57 $41 $45 $47 $45

Illinois Basin 11800 3.4# $45 $38 $32 $35 $36 $37

Prior

PRB 8800 0.8# $10 $10 $12

CAPP 12500 1.6# $46 $48 $48

NAPP 13000 3.0# $45 $47 $47

Illinois Basin 11800 3.4# $35 $36 $38

Nat Gas Pricing ($/mmBtu)

Current Forecast $4.25 $2.62 $2.55 $3.10 $2.90 $2.75

Prior $3.45 $3.20 $3.75

Source: Bloomberg, Morgan Stanley Research Estimates. Note: CAPP refers to Central Appalachia, NAPP to Northern Appalachia, PRB to Powder River Basin, and ILB to Illinois Basin

Cross-Sector Implications of Our Natural Gas & Coal Outlook:

E&Ps: We are reducing price targets for our lower gas price forecastand downgrading GPOR. We have reduced the long-term Henry Hubnatural gas price assumption in our models from $3.75 to $2.75 toreflect the more robust natural gas supply growth that we expectthrough 2020, particularly as associated gas production reboundsand will likely meet the majority of demand growth. We are loweringour price targets for the natural gas producers by an average of 31%.We are downgrading GPOR given its challenged outlook among thenatural gas producers in this lower gas price environment relative toour prior natural gas price deck. We prefer oil exposure over gas.

Merchant Power: The reduction in our long-term gas forecast leadsto 1-20% PT reductions across our merchant power coverage, but westill see several valuation dislocations in the group, robust cash flowgeneration, and a constructive setup for some merchant power-re-lated equities in 2017. Overall, we continue to hold an Attractiveindustry view of Diversified Utilities and Independent Power Produc-ers (IPPs). This year we predict a more stable power price outlook,with more upside drivers than downside risk and a market environ-ment where power prices could outperform gas. Merchant powerstocks also trade at 20-40%+ free cash flow to equity yields using thecurrent forward curve, by our estimates. On average, current stockprices imply a long-term gas price in-line with our revised outlook,however there is wide dispersion within the group. We are downgrad-ing Exelon (EXC) to Equal-weight, while Overweight-rated Dynegy(DYN) continues to screen most favorably in the group and remainsour top pick.

Midstream: With both the demand and supply of gas projectedhigher than in our previous models, the midstream sector shouldbenefit from the higher volumes as well as in three additional ways:greater pipe and processing project growth, reduced recontractingrisk, and better NGL (natural gas liquids) fundamentals.

LNG Export: Low US gas prices improves LNG (liquified natural gas)export economics; raising Cheniere's PT to $55 from $50 and remain-ing Overweight. US LNG exporters like Cheniere are the key benefici-aries of the structural pressure on long-term US gas prices, makingtheir volume more competitive in the global market. US LNG export-ers would be able to source gas at even lower cost increasing theirmargins on existing liquefaction.

Petchems: We model a 10c/gal premium to fuel-value (FV) for eth-ane in 2H17+, as new ethylene startups drive incremental ethanedemand. Ethane is the most widely used feedstock for US ethylene


MExhibit17:Several Gas Exposed Equities Reflect Long-Term Gas Prices Above OurForecast


production, which when oversupplied tends to be priced at its fuelvalue equivalent (i.e., the btu value of "rejecting" or leaving ethane inthe natural gas stream). This has generally been the case over thepast few years as the US shale boom has driven ethane supply growthwell in excess of petrochemical demand. We expect the ethane bal-ance to remain in surplus through the wave of new ethylene startups,but we expect a modest premium to FV to develop in order to coverthe transportation and tariff costs required to bring currently"rejected" ethane to market. Our estimated premium to FV is lessthan many bears and industry consultants contend (in somecases up to 30c/gal above FV).

Ags/Fertilizer: Natural gas is the principal raw material used in thenitrogen fertilizer production process and typically accounts for overhalf of total production costs. North American nitrogen companieshave been competitively advantaged given their access to low-costnatural gas. Using MSe revised forecast for natural gas rather thanthe futures curve would impact our EPS estimates as follows: CF:2017 +$0.02 (+5.7%); 2018 +$0.10 (+16.1%); AGU: 2017 +$0.05(+1.0%); 2018 +$0.05 (+0.9%); POT: 2017 +$0.01 (+1.6%); 2018+$0.01 (+1.3%). We note that: (1) CF is a nitrogen pure play, thoughit has hedged 45% of its 2017 natural gas requirements at $3.28 and10% of its 2018 natural gas requirements at $3.21, partially limitingthe impact of natural gas price volatility; (2) Agrium is a diversifiedglobal crop input and agricultural services provider with nitrogenrepresenting ~19% of 2017E EBITDA; and (3) Potash Corp. is one ofthe largest global fertilizer companies by capacity with nitrogen rep-resenting ~29% of 2017E EBITDA. Our estimates — and, we believe,consensus — uses the futures curve.

Rails: Coal is ~15% of the US rails' revenues on average and has beenin secular decline over the past decade. Last year, we noted an oppor-tunity for coal to see a short-term rally in 2017 (potentially spillingover to 2018) as natural gas prices were expected to reach ~$3.50and saw rails (UNP) exposed to Western coal to benefit the mostfrom near-term higher gas prices over rails (CSX/NSC) exposed toEastern coals. Given our Commodity team’s lowered natural gasprice outlook, we are decreasing the magnitude and duration of thetailwind from utility coal volumes at the US rails. We are cutting util-ity coal volumes for UNP, CSX, and NSC. As such, our price targets forUNP and NSC decrease by 2-3%. CSX's PT is unchanged as coal head-winds are offset by non-coal tailwinds.

12

MNatural Gas: Lower for Longer - Sub $3 Is the New NormalSeveral factors pressure near and long-term gas prices. The mostnotable of these is a precipitous decline in breakevens for unconven-tional US oil plays. We expect improved oil economics, particularly inthe gas-heavy Permian Basin, to drive rapid growth in associated gasproduction, regardless of how low gas prices fall. On the gas side,productivity improvements have also taken hold, with breakevensacross several key plays now well below $3. Furthermore, midstreaminfrastructure expansions in 2018 will unleash more low-cost supplyfrom Appalachia, narrowing US differentials and pressuring HenryHub prices. In power, the end of drought conditions in the western USwill allow hydro to displace gas. Longer term, declining powerdemand and growth in renewables gradually erode gas and coal gen-eration needs. As a result, the window for the gas price bull case toplay out is quickly closing. Accordingly, we are revising our price fore-casts lower. While 2017 remains tight, we see risks skewed to thedownside beyond 2017.

2017: Yet another year of mild winter weather has loosened the sup-ply-demand outlook for the balance of the year, eroding much of thenear term bull case for natural gas. We forecast end-March invento-ries of ~2 Tcf, ~490 Bcf below 2016 levels but above the 5-year aver-age. Over the upcoming summer, production growth of 1.2 Bcf/d YoYoffsets roughly 40% of the YoY increase in non-power demand.Lastly, wetter conditions in the western US should drive hydropowergeneration higher, displacing the need for gas. On net, we forecastthat Apr-Oct power demand of 26.5 Bcf/day will be adequate to refillinventories. Using our coal/gas dispatch models, this translates to$3.15/MMbtu.

1. Base case: We assume 10-year normal CDDs for the summerperiod, and improvement in hydro generation, and 1.2 Bcf/d ofsupply growth. We estimate net power demand of 26.5 Bcf/d willbe needed to drive end-October inventories of 3.85 Tcf, requiringprices to average $3.15 for the balance of the year.

2. Bull case: A repeat of warm summer weather, comparable to2016, and no improvement in hydrology in the western US. Asso-ciated gas growth fails to materialize, and instead remains flatwith winter 2016/17 levels. Net power demand of 25.1 Bcf/d wouldbe needed to drive end-October inventories of 3.85 Tcf, requiringprices to average $3.75 for the balance of the year.

3. Bear case: Western hydro matches peak levels seen in 2011, sup-ply growth surprises to the upside at 2 Bcf/d year-over-year.

Exhibit 18:We are Cutting Our Gas Forecast, Which is Now Below Forwards

Source: Bloomberg, Morgan Stanley Commodities Research estimates, forward curve as of 3/24/2017.

Exports to Mexico remain flat with 2016 levels due to infrastruc-ture limitations south of the border. Net power demand of 28.2Bcf/d would be needed to drive end-October inventories of 3.85Tcf, requiring prices to average $2.75 for the balance of the year.

Exhibit 19:Varying Coal-Gas Switching Needs Drive Our Bull and Bear Case Esti-mates

$3.75

$3.15

$2.75

-6

-5

-4

-3

-2

-1

0

$1.50

$2.00

$2.50

$3.00

$3.50

$4.00

Bull Base Bear

Left: 2017 Summer Prices ($/Mcf)

Summer 17 EP Needs YoY NG Price

Right:YoY Summer EP Needs (Bcf/d)

Source: Morgan Stanley Research. Note: EP = "Electric Power"


MExhibit 20:We Forecast Supply Growth Catching Up with Demand by 2018

-6

-4

-2

0

2

4

6

8

2013 2014 2015 2016 2017e 2018e

(YoY Demand Growth By Source vs YoY Supply Growth, Bcf/d)

Industrial Lease/Pipeline Mexico Exports

LNG Exports Storage Demand EP

Heating YoY Demand (Ex EP) YoY Supply (Prod+Imp)

Source: Morgan Stanley Research. Note: EP = "Electric Power"

2018: By early 2018, pipeline expansions and growth in associatedgas allow for low-cost supply to meet growth in demand. While early2018 has the potential for high prices if additional infrastructuredelays occur, our latest forecast calls for adequate pipeline expan-sion and production growth by January/February. Furthermore, weexpect more Gulf Coast production to hit the market in 2018 fromdry gas in the Haynesville and associated gas from the Permian. As aresult, we are reducing our 2018 forecast from $3.20/MMbtu to$2.90, implying downside to the current forward curve and equitymarket expectations.

1. Base case: We assume 30-year normal HDDs for the Nov-Marperiod, which results in end-March 2016 inventories of 1675 Tcf,326 Bcf below estimated 2017 levels and in line with 2013-2017averages. Summer 2018 total dry gas production of 78.5 Bcf/d.Average price of $2.75 needed during the summer months to refillinventories.

2. Bull case: We assume normal weather, but oil prices remain at$50/bbl, reducing 2018 associated gas by 1.2 Bcf/day, but partiallyoffset by higher Haynesville production in response to higher gasprices, leading to summer dry gas production of 77.7 Bcf/d.2010/2011 a winter analog, which fell approximately one standarddeviation colder than the 20-year average (NOAA HDD data avail-able back to 1997); this would send end-March inventories to 1451Bcf. Average price of $3.50 is needed to refill inventories.

3. Bear case: We assume a 2001/2002 winter analog, which fellapproximately one standard deviation warmer than the 20-yearaverage; this would result in end-March inventories of 2417 Bcf,416 Bcf above 2017 levels and 727 Bcf above previous 5-year aver-ages. Summer 2018 total dry gas production flat with base caseat 78.5 Bcf/d. Average price of $2.35 is needed to refill inventories.

Long Term: We are reducing our long-term natural gas price forecastby nearly 27%, from $3.75 to $2.75. Our revised outlook assumes$2.25-2.50 prices across Appalachia. Due to higher Gulf Coast supplyfrom associated gas and the Haynesville, we forecast a smallerdemand pull out of Appalachia, and no longer expect price differen-tials to trade to full transport costs. At these prices, we believe E&P'scan generate adequate ~20% returns and meet demand needs. Whileadditional improvements in productivity are possible, we expect thisto be largely offset by cost inflation over the next several years. Ourrevised forecast is below the forward curve and what is priced intomany gas-exposed equities.

14

MFor the second year in a row, mild winter weather set the tone fornatural gas. Going into 2017, the outlook for gas was the most bullishit had been in years. Production was under pressure from low com-modity prices and structural demand growth was starting to arrive.However, despite tight market conditions, surprisingly mild weatherconditions quickly loosened balances. Cumulative populationweighted gas heating degree days (GWHDDs) were ~15% below the30-year normal over the November-February period, with the mostextreme mild temperatures arriving in February. As a result, we nowforecast end-March inventories of ~2 Tcf, roughly 500 Bcf above ourestimate assuming normal weather. In addition to mild tempera-tures, wet conditions in the western US have significantly improvedthe drought conditions seen over the last several years. While under-lying demand for gas remains strong, with structural growth intactfor the balance of the year, the market no longer needs a large reduc-tion in power demand (via higher gas prices) to remain balanced.Lastly, we estimate supply may surprise to the upside in 2H17. Wenow forecast Henry Hub prices of $3.15/MMBtu for the balance of theyear, versus $3.50/MMBtu previously.

Winter 2016/17 Review: Mild Winter Created a Gas Glut...Again

Exhibit 21:Winter 2016/17 Saw Milder than Normal Weather...

0

100

200

300

400

500

600

700

800

900

1,000

Nov Dec Jan Feb

Gas Weighted Heating Degree Days

2017 2016 30-Year Normal

Source: Morgan Stanley Research, NOAA

Exhibit 22:...Driving Above-Normal End-March Inventories

0

500

1,000

1,500

2,000

2,500

3,000

3,500

4,000

4,500

Jan-17 Mar-17 May-17 Jul-17 Sep-17 Nov-17

12-16 range Avg 2017 2016

Gas Inventories (Bcf)

Source: Morgan Stanley Research, EIA, Bloomberg


M

Exhibit 25:Cross-Border Expansions to Mexico Will See a Healthy Increase in2017

Company US-Mexico Project MMcf/d Orig ISD Status

OneOK Roadrunner Phase 2 400 4Q16 In-Service

ETP Comanche Trail 1,100 1Q17 In-Service

ETP Trans-Pecos 1,400 1Q17 98% Complete

Howard Nueva Era 504 Jun-17 On time


Exhibit 23:We Forecast ~5 Bcf/day of Non-Power Demand Growth 2017-18


The Positive: Structural Demand Growth Remains Intact

While mild weather significantly reduced residential and commercialheating needs over the past few months, the underlying weather-normalized demand growth trend is strong. We continue to forecasta nearly ~5 Bcf/d (10%) increase in non-power demand for natural gasover the next two years primarily driven by exports and increasedindustrial activity.

Exports provide demand support 2017 and beyond. In summer2017, we forecast 2.3 Bcf/d in combined year-over-year exportgrowth from LNG and Mexico. On LNG exports, aside from an outageat Sabine Pass in early March, utilization has consistently come in>90% as US arbs have remained open to Asia and Europe despitestill-depressed global LNG prices. We expect the similar utilizationfrom Sabine Pass train 3 (startup achieved earlier in 1Q17) and train4 (startup assumed in late 2Q17, with substantial completion in2H17). Summer-over-summer, we expect Sabine Pass to add ~1.5Bcf/d of average demand (Train 1 operated for most of summer 2016,while trains 2-4 will be incremental this year). Later in the year, the4Q17e startup of Cove Point should produce incremental LNG exportgrowth of 0.7 Bcf/day. For Mexico, cross-border pipeline capacity isexpected to increase in 2017 with the completions of ETP's Coman-che Trail (1Q17), Trans Pecos (end Mar-17) and Howard Energy'sNueva Era (Jun-17). That said, Mexican gas power plant additions totalonly 3.7 GW or 0.5-0.6 Bcf/d in 2017. This dynamic should limit actualexports to Mexico at levels well below that implied by pipelineexpansions.

Exhibit 24:When Operating, LNG Feedgas Demand Has Often Outpaced Name-plate Capacity

0

1

2

3

4

5

6

7

8

9

Jan-1

6

Ma

y-1

6

Sep-1

6

Jan-1

7

Ma

y-1

7

Sep-1

7

Jan-1

8

Ma

y-1

8

Sep-1

8

Jan-1

9

Ma

y-1

9

Sep-1

9

Jan-2

0

Ma

y-2

0

Sep-2

0

(Cumulative LNG export capacity vs monthly feedgas demand, Bcf/d) Corpus Christi T2

Corpus Christi T1

Freeport T3

Cameron T3

Cameron T2

Sabine Pass T5

Freeport T2

Cameron T1

Freeport T1

Cove Point

Sabine Pass T4

Sabine Pass T3

Sabine Pass T2

Sabine Pass T1

Average FeedgasDemand

Fall '16 Maintenance,

T1/T2 fully offline

Source: Bentek Energy, Morgan Stanley ResearchIndustrial demand positioned for continued growth. After con-tracting in 2015, industrial demand began to show signs of growth in2016, improving 0.4 Bcf/d year-over year. Over the next severalyears, we expect several gas-intensive, US-based facilities to comeonline. A buildup of the industrial components by segment (weather,oil/gas price ratios and IP/Other impacts) continues to indicate thatnegative trends from all categories are offsetting a portion of thenew demand from ~886 MMcf/d of new project capacity added dur-ing 2016. We forecast that improving oil/gas price ratios should beginto support modestly better underlying demand. Looking forward to2018, we forecast an incremental ~0.9 Bcf/d driven by new facilitiescoming online assuming flattish underlying demand.

16

M

Exhibit 27:Our E&P and Chemicals team estimate an ethane price of $0.30 to$0.40/gallon is required to incentivize sufficient recovery to meet incre-mental demand in 2018

$0.20

$0.25

$0.30

$0.35

$0.40

$0.45

$0.50

$0.55

$0.60

0 50 100 150 200 250 300 350 400 450 500 550 600 650 700 750 800Ethane Supply (MBbls/d)

Prices to Incentivize E&P Ethane Recovery ($/gal)

Breakeven Breakeven (ex. Transport)

2018 Cumulative Incremental Ethane Demand +Exports (482 MBbls/d)

TX Gulf Coast

LA Gulf Coast

New Mexico

Midcon TX Inland

Appalachia

Rockies

Upper Midwest

Rockies Midcon Appalachia

New Mexico TX Inland

TX Gulf Coast Upper Midwest

2018 Cumulative Incremental Ethane Demand (272

LA Gulf Coast

2018 Cumulative Incremental Ethane Demand Less Propane Switching (163 MBbls/d)

Source: Envantage, Platts, Morgan Stanley Research estimates

Exhibit 26:Industrial Demand Set to Accelerate into 2018

Source: Morgan Stanley Research estimates, Bentek

Improving NGL markets in 2017/2018 reduces dry gas produc-tion growth as rejection levels fall. Ethane frac spreads were vola-tile through 2016, but have held at mostly negative levels since 2013as an oversupply of ethane and propane all but eliminated extractionmargins. We do expect the outlook for NGL (natural gas liquids) toimprove from a number of ethane cracker and export expansions. Weanticipate ethane rejection, which is estimated to be ~800 kb/d in2016, will be the first to gradually unwind as frac margins improvewith NGL prices (and still relatively low gas prices) . Overall, we fore-cast this dynamic to drive a ~1.4 Bcf/d reduction in effective dry gasvolumes in 2018 as compared to 2016 levels.

Offsetting strong demand are several negatives, perhaps most nota-bly improvements in well productivity and drilling efficiency in bothoil and gas, which continue to drive costs and breakevens down. Thisdynamic supports more supply at lower prices than ever before. Fur-thermore, midstream infrastructure expansions in 2018 will unleashmore low-cost supply from Appalachia, narrowing US differentialsand pressuring Henry Hub prices. On top of this, growth in dry gasproduction out of the Haynesville and more associated gas from the

The Negatives: Productivity, Infrastructure, Rig Counts & Hydro

Permian and Oklahoma represent low-cost sources of supply closeto demand in the US Gulf Coast (USGC) region. Lastly, improvedhydrology in the western US should reduce dependence on gas gen-eration, while at the same time renewables are offsetting much ofthe positive power burn benefits from planned coal retirements. Asa result, the window for the gas price bull case to play out is quicklyclosing.


M

Exhibit 28:Oil Rigs in the Permian Basin Have Increased 200% Since Mid-2016

0

100

200

300

400

500

600

Jan-15 Apr-15 Jul-15 Oct-15 Jan-16 Apr-16 Jul-16 Oct-16 Jan-17

Permian Basin Rigs


Oil: Improving shale economics coupled with a stronger globaloil market is negative for gas. Over the last several years, innova-tion has driven substantial reduction in unconventional shale wellcosts while yields have moved higher. The result has been a precipi-tous 60-70% decline in breakeven prices for key shale plays. Themost notable declines have been in the Permian in Texas, where20-33% (lower in the Midland, higher in the Delaware) of the energyoutput is natural gas. In response to improved economics, rig countshave increased 200% year-to-date, a trend we expect to continue.There has also been a shift in activity into the gas-heavy Delawaresection of the play. The result is substantial growth in associated gas,regardless of how low gas prices fall. In fact, by 2020 we expect totalassociated gas to grow by ~7.5 Bcf/day, mostly from the Permian. Thisgas is roughly equivalent to all incremental planned LNG export pro-jects, and is geographically close to demand growth in the US GulfCoast.

Exhibit 29:Lower Well Costs...

$7.1 $7.7 $7.7

$6.6

$5.7

$0.0

$1.0

$2.0

$3.0

$4.0

$5.0

$6.0

$7.0

$8.0

$9.0

2012 2013 2014 2015 2016

Delaware Well Cost (Million USD)


Exhibit 30:…Coupled With Higher Recoveries

-

20

40

60

80

100

120

140

160

0 2 4 6 8 10 12 14 16 18 20 22 24 26 28 30 32 34 36

Barr

els

of

Oil

(000's

)

Months

Average Delaware Well Production

2012 2013 2014 2015 2016

Source: DrillingInfo

Exhibit 31:Have Driven 60-70% Declines in Permian Oil Breakevens...


Exhibit 32:...Supporting Rapid Growth in Associated Gas, Regardless of How LowGas Prices Fall

0

1,000

2,000

3,000

4,000

5,000

6,000

7,000

8,000

9,000

2014 2015 2016 2017e 2018e 2019e 2020e

Permian Oil & Gas Production Oil Production (mbld)Associated Gas (mmcf/d)


18

M

Exhibit 35:Pipeline Expansions Have Faced Delays, but the Majority of 2017 Pipes Are Now on Pace to Be Done in 2018

Company Northeast Project MMcf/d Orig ISD Status

TGT OH-LA Access Project 626 Jun-16 In-service

EQT Ohio Valley Connector 850 Jun-16 In-service

TETCO Gulf Markets Expansion 250 Nov-16 In-service

REX Zone 3 Cap Enhancement 800 Dec-16 In-service

TGT Northern Supply Access Project 384 Apr-17 On time / Under Construction

NFG Northern Access Project 497 Nov-17 Delayed -2Q18 ISD

Rover Rover Pipeline ph1/ph2 3,250 Jun-17 Delayed - 3Q17/4Q17 ISD

Transco Atlantic Sunrise 1,700 Jul-17 Delayed - 3Q18 ISD

TGP Southwest Louisiana 900 Sep-17 Delayed - 1Q2018 ISD

TETCO Lebanon Extension 102 Nov-17 Delayed - 4Q17 ISD

TETCO Adair Southwest 200 Nov-17 Delayed - 4Q17 ISD

TETCO Access South 320 Nov-17 Delayed - 4Q17 ISD

PennEast PennEast Pipeline 1,000 Nov-17 Delayed - 4Q18 ISD

TCO Leach Xpress 1,530 Nov-17 Delayed - 4Q17 ISD

NEXUS NEXUS Gas Transmission 1,500 Nov-17 Delayed - 2Q18 ISD

MVP Mountain Valley Pipeline 2,000 Nov-17 Delayed - 4Q18 ISD

Source: Morgan Stanley Research, Company Data. Note: "Status" represents MS Research estimate.

Exhibit 34:...And Marcellus Drilled But Uncompleted Well Inventory Levels HaveStabilized, After Declining in Early 2016

0

200

400

600

800

1000

1200

1400

1600

1800

20001H

11

2H

11

1H

12

2H

12

1H

13

2H

13

1H

14

2H

14

Jan-1

5

Feb

-15

Ma

r-1

5

Apr-

15

Ma

y-1

5

Jun-1

5

Jul-1

5

Aug-1

5

Sep-1

5

Oct-

15

No

v-1

5

De

c-1

5

Jan-1

6

Feb

-16

Ma

r-1

6

Apr-

16

Ma

y-1

6

Jun-1

6

Jul-1

6

Aug-1

6

Sep-1

6

Oct-

16

No

v-1

6

De

c-1

6

(PA DUCs by date spudded)

2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016

Source: Morgan Stanley Research, PA DEC

Exhibit 33:Rig Counts Have Nearly Doubled Since Mid-2016...

-

20

40

60

80

100

120

140

160

Jan-1

6

Feb-1

6

Mar-

16

Apr-

16

May-1

6

Jun-1

6

Jul-16

Aug-1

6

Sep-1

6

Oct-

16

Nov-1

6

Dec-1

6

Jan-1

7

Feb-1

7

Mar-

17

Gas Rig Count

Other Utica Marcellus Haynesville

Source: Morgan Stanley Research, Bloomberg, Baker Hughes

Growth in gas rig counts supports stronger production growth.Gas rig counts have nearly doubled from the lows seen in mid-2016.This dynamic is driven by higher commodity prices and improvingbreakevens from efficiency improvements, as noted above. In theHaynesville, the rig count has risen from 12 in September to 35 cur-rently. In the Northeast, drilled but uncompleted (DUC) well countshave begun to stabilize after steadily declining mid-2015 throughmid-2017. These dynamics, coupled with increased oil activity (andthe resulting growth in associated gas), points to strong productiongrowth in 2H17 into 2018.

Despite delays, substantial pipeline capacity is slated to comeonline in 2018... Over the past year, there has been no shortage ofpipeline delays for expansions out of Appalachia. Per our recentcount, 12 Bcf/d of pipeline expansion capacity that would have other-wise come into service during 2017 is likely delayed into 2018 or later.Under normal winter weather, this dynamic would have tightenedthe gas market in 2017 by limiting low cost supply growth out of theMarcellus and Utica. However, mild weather has alleviated much ofthe need for this incremental supply - effectively bridging the gapuntil more meaningful expansions enter service in 2018. While weforecast modest Marcellus/Utica production growth of 2.3 Bcf/d in2017, we expect a meaningful 4.3 Bcf/d increase in 2018. This com-pares to average growth of 3.5 Bcf/d in 2012-16.


M

...While non-Northeast supply is beginning to show signs ofgrowth. Outside the Marcellus/Utica, upstream activity has beenincreasing due largely to the return of growth in the Haynesville andan improved oil outlook. In aggregate, we forecast non-Northeastsupply to decline modestly in summer 2017 (~0.4 Bcf/day) which isa strong change from ~4.1 Bcf/d declines seen in summer 2016.Non-Northeast dry gas basins have also seen a modest increase in activityyear to-date with improved pricing and productivity, particularlywithin the Haynesville. We now expect the recent trend of aggregatedeclines to stop in summer 2017, with our forecast calling for flattishproduction year-over-year driven by the first year of growth since2010 in the Haynesville. This trend accelerates by 2018, with our esti-mates calling for ~0.6 Bcf/d of growth. On the associated gas side, animproved near term oil outlook is expected to add momentum to analready resilient set of producers, particularly in the Permian. Webelieve associated gas production will decline a modest 0.3 Bcf/dyear-over-year in summer 2017, before accelerating in the back halfof the year and returning to growth of ~2.5 Bcf/d in 2018, comparedto essentially flat YoY in 2016.

Exhibit 36:Over 30 Bcf/d of Take-Away Capacity From Appalachia Is Scheduled toBe Online by 2019, After Adjusting for Delays

-

5

10

15

20

25

30

35

40

1Q14 4Q14 3Q15 2Q16 1Q17 4Q17 3Q18 2Q19

Thousands

Planned Appalachia Pipeline Capacity by End-Market (Bcf/d)

MidCon/Canada MidAtlantic/South Northeast Premium


Haynesville activity increasing, driven by improved economics.In the Haynesville, the rig count has risen from 12 in September to 35currently. This dynamic is the result of improving well economics.Average initial production (IP) rates have trended up over the pastseveral years, driven in a large part by improved drilling techniquesand longer laterals. We forecast 20% IRR breakevens are now com-fortably below $3/MMbtu. The stronger gas prices currently, relativeto the lows seen this time in 2016, supports increased upstreamactivity in the basin. Our production model indicates that dry gas pro-duction could grow by ~0.6 Bcf/d by the end of 2017, and a compara-ble amount in 2018.

Exhibit 37:Supply Growth Expected to Return in 2017-18, and Not Just in theNortheast

-6.0

-4.0

-2.0

0.0

2.0

4.0

6.0

8.0

2013 2014 2015 2016e 2017e 2018e

(YoY change in gross production by type, Bcf/d)

Northeast Non-NE shale Associated Gas

Conventional Coalbed Methane Total Gross YoY

Source: EIA, DrillingInfo, Morgan Stanley Research estimates

Exhibit 38:Haynesville Breakevens Now Sit Comfortably Below $3/MMbtu...

$1.50

$2.17 $2.28 $2.40

$2.83

$3.42

$0.00$0.50$1.00$1.50$2.00$2.50$3.00$3.50$4.00

Terryville -Upper Red

SWPA -Marcellus

NEPA -Marcellus

Haynesville Ohio Utica -Dry Gas

Fayetteville

Henry Hub Breakevens Assumes 20% IRR & $60/Bbl WTI


Exhibit 39:...Supporting Higher Rig Counts and a Return to Growth

0

20

40

60

80

100

120

140

160

-

2.0

4.0

6.0

8.0

10.0

12.0

Jan-11 Jan-12 Jan-13 Jan-14 Jan-15 Jan-16 Jan-17 Jan-18 Jan-19 Jan-20

Haynesville/Mid-Bossier Production Bcf/d

Growth

2016

2015

2014

2013

2012

2011

2010

Pre2010

Rigs

Rigs

Source: Morgan Stanley Research, EIA, DrillingInfo

20

MExhibit 40:17 GW of Coal Retirements and Conversions Have Been Announced2017-20...

0

1

2

3

4

5

6

7

8

2017 2018 2019 2020

Coal Retirements & Conversions (GW)

Source: Morgan Stanley Research, SNL

Exhibit 41:...but Low Utilization Rates Limit the Gas Demand Impact

-

0.1

0.2

0.3

0.4

0.5

0.6

0.7

0.8

0

5,000

10,000

15,000

20,000

25,000

30,000

2017 2018 2019 2020

Cum

mula

tive G

as D

em

and

Impact (B

cf/

d)

Lost C

oal G

enera

tion (

GW

h)


Hydrology & Power Burn

The power sector remains the key balancing factor for the natu-ral gas market. Gas supply/demand balances in 2015 and 2016 bothrequired record amounts of power demand and extreme low naturalgas prices relative to coal to help temper injections and avoid physi-cal storage constraints. Summer 2017 is setting up to be a reversal ofthis trend, where instead lower power demand (and higher prices rel-ative to coal) is needed despite above-average storage. Using our pro-prietary coal/gas switching model, we estimate that at natural gasprices of $3.15/MMbtu, power demand will decline 3.5 Bcf/d YoY insummer 2017 and help refill inventories to 3.85 Tcf. As a result, in thatevent, coal would inevitably take some market share back in someregions. However, limited structural growth, lower seasonal outa-ges, and improved hydrology in the West all drive lower power burn,even before accounting for economics driven fuel switching. We seethe following key drivers in 2017:

Coal Retirements/Conversions: 6 GW of coal retirements and 1 GWof coal plant conversions are slated to occur in 2017. However, theseplants tend to have very low utilization rates (in the 30-40% range).As a result we estimate only a modest 0.3 Bcf/d gas demand increaseas these plants go away.

Weather: Summer 2016 cooling degree day (CDD) totals of 1,474were higher than the 10-year average of 1,342, so adjustments backto normal summer temperatures result in a ~0.3 Bcf/d gas demandreduction for the US.

Hydro: After years of drought, wet winter conditions have drivensubstantial increases in reservoir levels across much of the westernUS. Furthermore, snowpack in California's Sierra Nevada mountainshas now reached 180% of normal, creating a steady supply of addi-tional water as melting occurs into the spring and summer. As a par-tial offset, snowpack in parts of the Pacific Northwest is currentlyslightly below normal. On net, this will result in stronger hydro-power production, which we estimate will displace ~0.4 Bcf/day ofgas generation on average April-October.

Exhibit 42:California Snowpack Is ~180% of Normal...

0%

50%

100%

150%

200%

Northern Sierra Central Sierra Southern Sierra

California Snowpack (% of Normal) Mar-2016 Mar-2017

Normal

Source: Morgan Stanley Research, California Department of Water Resources


MExhibit 43:...Higher Hydropower Production Will Displace Western Gas in Sum-mer 2017

-0.7

-0.6

-0.5

-0.4

-0.3

-0.2

-0.1

0

Apr-

2017

May-2

017

Jun-2

017

Jul-2017

Aug-2

017

Sep-2

017

Oct-

2017

Estimated Hydro Impact on YoY Gas Demand (Bcf/day)

Source: Morgan Stanley Research, EIA

Exhibit 44:We Forecast Hydro Generation Above the 5-year Average (2012-16),but Below 2011 Levels

15,000

17,000

19,000

21,000

23,000

25,000

27,000

29,000

31,000

33,000

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

5-yr Range

2017E

2016

5-yr Average

2011

Monthly Hydro

Generation (GWh)

Source: Morgan Stanley Research estimates, EIA

Wind/Solar: An incremental 8.8 GW of wind generation and 7GW ofutility-scale solar generation offset a combined 0.7 Bcf/d from sum-mer gas demand after correcting for capacity factors. Solar capacityadditions are mostly in the west, but activity in the Southeast andTexas has also begun to accelerate. Wind additions continue to beconcentrated in the central US, where they displace a mix of coal andgas.

Exhibit 45:Wind Additions Erode ~0.2 Bcf/d of Gas Demand Summer-over-Sum-mer in 2017….


Exhibit 46:...While Solar Erodes an Incremental 0.5 Bcf/d


Coal to Gas Switching: In addition to the factors above, we estimate2.4 Bcf/d of economics driven gas-to-coal switching (away from gas,over to coal) is needed to balance the market YoY. Using our powerplant dispatch model, we estimate a gas price of ~$3.15 is needed toincentivize this to occur.

22

M

Exhibit 47:We Forecast a 3.5 Bcf/d Reduction in Total Power Sector Gas DemandSummer-over-Summer in 2017


Exhibit 48:Fuel Switching Capability Remains Robust

(6)(5)(4)(3)(2)(1)01234

$2.25 $2.50 $2.75 $3.15 $3.25 $3.50 $3.75

YoY Change in Summer Gas Burn at Various Henry Hub Prices (Bcf/d)

Base Case


Looking forward to 2018, meaningful supply growth puts fur-ther pressure on the market. Supply growth, lead by associated gasand infrastructure expansion out of the northeast more than offsetsstructural demand by the second half of 2018. In aggregate, we fore-cast a 5.5 Bcf/d year-over-year increase in dry gas supply in 2018. Akey driver of this growth is associated gas, driven mostly by higher oilproduction levels in the Permian. We expect drilling activity to shiftto the gassier Delaware portion of the basin, where roughly ⅓ of the

Exhibit 49:Strong Supply Growth Will Again Require Power Burn to Balance the Market in 2018, Requiring Lower Gas Prices

-3.0

-2.0

-1.0

0.0

1.0

2.0

3.0

4.0

5.0

6.0

7.0

Prod CAD Imp LNG Imp(Exp)

Mex Exp Res/Com Power Industrial Net

W 17/18 S 18

Supply Demand

YoY Balance Changes (Bcf/d)

Source: EIA, Bentek Energy, Morgan Stanley Research

production is natural gas (on an energy content basis). In the North-east, we expect ~6 Bcf/d of pipeline expansions in the first half of theyear to support meaningful Marcellus/Utica supply growth into thesummer, pressuring Henry Hub prices. In order to balance the market,the power sector will again be called upon to increase consumption(via lower gas prices). We estimate a 1.2 Bcf/d increase in power sec-tor gas burn in summer 2018, relative to 2017, which will requireHenry Hub prices to average ~$2.75/MMbtu over the period.


MExhibit 50:US Natural Gas Supply Demand ForecastSummary

SUPPLY 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018

Gross Production L48 55.7 58.0 60.7 62.3 64.7 69.3 72.1 72.1 77.3 81.4 80.4 82.0 88.6

YoY 0.0 2.3 2.7 1.6 2.4 4.6 2.7 0.0 5.3 4.1 -1.0 1.6 6.6

L48 Gas (Conventional) 48.8 40.6 40.9 39.1 36.0 33.4 33.9 29.2 27.5 26.5 25.7 25.2 24.7

YoY 0.0 -8.2 0.3 -1.8 -3.2 -2.6 0.5 -4.6 -1.8 -0.9 -0.9 -0.5 -0.5

CBM 3.6 5.5 5.5 5.5 5.3 4.9 4.2 3.9 3.6 3.2 2.6 2.3 2.1

YoY 0.0 1.9 0.0 0.0 -0.3 -0.4 -0.7 -0.3 -0.3 -0.3 -0.6 -0.2 -0.2

Onshore L48 Shale 1.8 5.5 7.8 10.8 15.9 23.3 28.8 32.7 38.3 42.4 43.4 45.4 50.3

YoY 0.0 3.7 2.4 3.0 5.1 7.4 5.5 3.9 5.6 4.1 1.0 2.1 4.9

Barnett 1.7 2.6 3.9 4.3 4.4 5.0 5.1 4.7 4.3 3.7 3.2 2.8 2.7

Fayetteville 0.0 0.2 0.7 1.4 2.1 2.6 2.8 2.8 2.8 2.5 2.0 1.7 1.6

Woodford 0.1 0.2 0.5 0.8 1.1 1.2 1.4 1.7 1.9 2.0 1.9 2.0 2.0

Haynesville 0.0 0.0 0.1 1.2 3.8 6.6 6.9 5.0 4.1 3.8 3.8 4.3 5.0

Marcellus 0.0 0.0 0.0 1.6 2.5 4.8 7.7 11.2 14.6 16.8 18.1 20.0 23.5

Eagle Ford 0.0 0.0 0.0 0.0 0.3 1.0 2.2 3.3 4.2 4.8 4.4 3.8 3.8

Utica 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.4 1.4 2.7 3.9 4.3 5.0

Onshore L48 Associated 6.9 6.5 6.4 6.8 7.6 7.8 5.2 6.2 8.0 9.2 9.4 9.1 11.5

YoY 0.0 -0.4 -0.1 0.4 0.7 0.2 -2.6 1.0 1.8 1.2 0.2 -0.4 2.4

Bakken 0.0 0.0 0.0 0.0 0.0 0.0 0.5 0.6 0.9 1.2 1.4 1.3 1.4

Eagle Ford 0.0 0.0 0.0 0.0 0.3 1.0 2.2 3.3 4.2 4.8 4.4 3.8 3.8

Permian 0.0 0.0 0.0 0.0 0.0 0.0 0.8 1.2 2.0 3.0 3.5 3.0 4.7

Mississippian 0.0 0.0 0.0 0.0 0.0 0.0 0.2 0.4 0.6 0.6 0.5 0.4 0.3

Denver Julesberg 0.0 0.0 0.0 0.0 0.0 0.0 0.2 0.4 0.6 0.7 0.6 1.0 1.1

Other L48 Associated 6.9 6.5 6.4 6.8 7.6 7.8 3.1 2.5 2.3 1.5 1.5 1.5 2.1

Offshore GOM 8.0 7.7 6.4 6.7 6.2 5.0 4.2 3.6 3.5 3.6 3.4 3.4 3.5

Balancing 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 -0.6 0.0 0.0

Dry Production L48 50.7 52.8 55.1 56.5 58.4 62.7 65.7 66.3 70.9 74.1 72.0 72.7 78.3

YoY 0.0 2.1 2.3 1.4 1.9 4.3 2.9 0.7 4.6 3.2 -2.1 0.8 5.5

NET IMPORTS

Canada 8.9 9.0 8.3 7.0 7.0 6.0 5.4 5.1 5.1 5.3 5.8 6.0 5.8

YoY 0.0 0.2 -0.8 -1.2 -0.1 -1.0 -0.5 -0.3 0.0 0.2 0.6 0.2 -0.2

Mexico -0.8 -0.6 -0.9 -0.9 -0.8 -1.4 -1.7 -1.8 -2.0 -2.9 -3.7 -4.3 -4.7

YoY 0.0 0.2 -0.2 0.0 0.0 -0.5 -0.3 -0.1 -0.2 -0.9 -0.8 -0.6 -0.4

LNG 1.4 2.0 0.9 1.1 1.0 0.8 0.4 0.3 0.1 0.2 -0.3 -1.8 -2.6

YoY 0.0 0.5 -1.1 0.3 -0.1 -0.2 -0.4 -0.1 -0.1 0.1 -0.4 -1.5 -0.8

Total Net Imports 9.5 10.4 8.3 7.3 7.1 5.4 4.2 3.6 3.2 2.6 1.9 -0.1 -1.5

YoY 0.0 0.9 -2.1 -0.9 -0.2 -1.8 -1.2 -0.6 -0.4 -0.7 -0.7 -1.9 -1.4

DEMAND

Residential/Commercial 19.8 21.4 22.0 21.7 21.7 21.7 19.3 22.5 23.6 21.6 20.5 21.4 22.2

YoY 0.0 1.5 0.7 -0.3 0.0 0.0 -2.4 3.3 1.0 -2.0 -1.1 1.0 0.7

Electric Power 17.0 18.7 18.2 18.8 20.2 20.7 24.9 22.4 22.3 26.5 27.2 24.4 24.8

YoY 0.0 1.7 -0.5 0.6 1.4 0.5 4.2 -2.5 -0.1 4.2 0.8 -2.9 0.4

Industrial Demand 17.9 18.3 18.2 16.9 18.7 19.2 19.8 20.4 21.0 20.7 21.1 21.3 22.2

YoY 0.0 0.4 0.0 -1.3 1.8 0.5 0.6 0.6 0.6 -0.3 0.4 0.2 0.9

Vehicle Demand 0.0 0.0 0.0 0.0 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1

YoY 0.0 0.0 0.0 0.0 0.1 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0

Lease Plant/Pipeline Fuel 4.7 5.1 5.1 5.3 5.4 5.5 5.8 6.3 6.1 6.2 6.1 6.4 7.0

YoY 0.0 0.3 0.0 0.2 0.0 0.1 0.3 0.5 -0.3 0.1 -0.1 0.3 0.6

Total Demand 59.5 63.4 63.6 62.8 66.1 67.1 69.8 71.7 73.0 75.0 75.0 73.6 76.3

YoY 0.0 3.9 0.2 -0.8 3.3 1.1 2.7 1.9 1.2 2.0 0.1 -1.4 2.6

BALACING ITEM 0.28 (0.54) 0.02 (0.25) 0.33 (0.24) (0.18) 0.11 (0.78) (0.55) (0.19) (0.10) (0.10)

STORAGE INJ/WTH

End March Inventory 1,692 1,603 1,266 1,660 1,652 1,577 2,473 1,720 857 1,480 2,495 2,001 1,675

Winter Draw - 1,849 2,299 1,740 2,157 2,274 1,331 2,209 2,960 2,107 1,456 2,022 2,190

End-October Inventory 3,452 3,565 3,399 3,810 3,851 3,804 3,929 3,817 3,587 3,951 4,022 3,865 3,916

Summer Injection 1,761 1,962 2,133 2,150 2,198 2,227 1,456 2,097 2,730 2,470 1,527 1,865 2,241

Forecast

Source: EIA, Drillinginfo, Bentek Energy, Morgan Stanley Research estimates

24

MLong-Term Gas: Cutting Forecast to $2.75

Exhibit51:Several Gas Exposed Equities Reflect Long-Term Gas Prices Above OurForecast


Exhibit 52:Associated Gas Meets ~60% of Demand Growth Through 2020

-5.9 -2.3 5.1 12.6

+0.7

2016-20 DemandGrowth (Bcf/d)

Net SupplyGrowth Needed

(Bcf/d)

Other AssociatedDeclines

PermianAssociated Gas

SCOOP/STACKAssociated Gas


We are reducing our long-term natural gas price fore-cast by 27%, from $3.75 to $2.75. Our revised outlookassumes $2.25-2.50 prices across Appalachia. Due tohigher Gulf Coast supply from associated gas and the Hay-nesville, we forecast a smaller demand pull out of Appala-chia, and no longer expect price differentials to trade to fulltransport costs. At these prices, we believe most E&Ps cangenerate adequate ~20% returns and meet demand needs.While additional improvements in productivity are possi-ble, we expect this to be largely offset by cost inflation overthe next several years. Prices may break below $2.75 forperiods, but strong coal-gas switching in the power sectorshould continue to create a soft floor below this level. Ourrevised forecast is below the forward curve and what ispriced into many gas-exposed equities.

Step change to supply outlook. We have held a bullish view of natu-ral gas (relative to consensus) over the past 12 months, primarily onthe thesis that Appalachia supply growth would be more subduedthan Street expectations. We still hold this view of more modestgrowth out of the basin than most anticipate. What has changed overthe past couple of months is the significant improvement in PermianBasin well productivity and the sharp increases in activity levels (i.e.,rig counts). Both have significantly outstripped our expectations(which were already robust). The Permian Basin, with some modestsupport from other oil plays, should prove sufficient to meet the sig-nificant demand growth through the end of the decade. We estimateassociated gas production will grow an average of 1.9 Bcf/d each yearin 2017-20.

Associated gas satisfies 60% of demand growth through 2020.In aggregate, we forecast US natural gas demand to grow 12.6 Bcf/din 2016-20, led by exports (LNG and Mexico). Over this same period,over 30 Bcf/d of pipeline expansions are planned to move gas fromthe low cost Marcellus/Utica basins to demand centers in the South-east, Gulf Coast, Midcon, and Northeast. Furthermore, roughly ~7.5Bcf/d of associated gas growth from unconventional oil activity satis-fies roughly 60% of new demand. The supply growth need net ofassociated gas is a very modest ~5.1 Bcf/d. Growth plans of just theAppalachian producers, with breakevens in the $1.50-2.50/MMbturange, are adequate to satisfy the remaining supply need. While theremight be brief periods of supply-demand mismatches driving bothpositive and negative volatility in gas prices, we believe this dynamic

supports normalized long-term prices of below $3. Given the largeamount of coal-gas switching that occurs at sub $2.75/MMbtu gas(driving increases in demand from the power sector), we see thislevel as the new long-term normal price for natural gas.

After undergoing a significant transformation, the PermianBasin should deliver supply growth similar to Appalachiathrough the balance of the decade. As recently as 2013, most E&Psviewed the Southern Delaware Basin as a marginally economic playthat could not compete with the Midland Basin's returns. Since then,dozens of E&Ps have entered the Delaware Basin through acquisi-tions, organic leasing, or both. Additionally, the northern Delawareand Midland Basins have both undergone dramatic improvements inproductivity at the same time that costs have fallen.


MExhibit 53:We Estimate Total US Demand Growth of 12.6 Bcf/d 2016-20, Lead by Exports

Bcf/d

2011 2012 2013 2014 2015 2016 2017e 2018e 2019e 2020e 2020-2016

Total US 68.4 71.4 73.5 74.9 77.7 79.7 80.9 84.9 90.2 92.3 12.6

Residential/Commercial 21.7 19.3 22.5 23.6 21.6 20.5 21.7 22.2 22.3 22.4 2.0

Industrial 19.2 19.8 20.4 21.0 20.7 21.1 21.3 22.2 22.7 23.2 2.1

Power 20.7 24.9 22.4 22.3 26.5 27.2 24.4 24.8 24.4 24.1 (3.2)

LNG Exports - - - - - 1.1 2.7 4.1 7.2 8.4 7.3

Mexico 1.4 1.7 1.8 2.0 2.9 3.7 4.3 4.7 6.1 6.7 3.0

Pipeline / Lease / Plant fuel 5.5 5.8 6.3 6.1 6.2 6.1 6.4 7.0 7.4 7.6 1.5

New Appalachia Pipeline Capacity 2.3 6.3 9.1 15.3 33.3 35.7 36.2 27.1

To Northeast 0.3 0.7 1.2 1.3 2.0 2.9 2.9 1.7

To MidAtlantic/South 1.3 3.3 4.2 6.7 19.0 20.5 21.0 16.8

To MidCon/Canada 0.6 2.4 3.7 7.3 12.3 12.3 12.3 8.6

ForecastActual


Exhibit 54:Oil Rigs in the Permian Basin Have Increased 200% Since Mid-2016

0

100

200

300

400

500

600

Jan-15 Apr-15 Jul-15 Oct-15 Jan-16 Apr-16 Jul-16 Oct-16 Jan-17

Permian Basin Rigs


STACK & SCOOP activity sufficient to deliver 2.3 Bcf/d of associ-ated gas growth through 2020. STACK resources are economic atlow oil prices sufficient to support a rig count of 49 today, up from8 in early 2014, when the play was in its infancy, at which time NFXwas the only operator with significant activity in the basin. Althoughmuch of the play has higher gas content, we estimate that much ofit generates attractive returns at $60 WTI oil even if realized gas pri-ces were zero. SCOOP activity has also picked up as productivityhas improved and operators have consolidated the play. Economicsare now attractive in both the gas and oil windows of the play.

Haynesville returns now strong enough for growth to return.New completion technology, lower well costs, combined with one ofthe most delineated unconventional gas plays in American combineto create a play competitive even in today's gas price environment.We expect 0.5 Bcf/d of average production growth per year in2017-20 at gas prices slightly below strip ($2.75-3.25 from nowthrough 2020).

Exhibit 55:Improved Haynesville Economics Support Higher Rig Counts and aReturn to Growth

0

20

40

60

80

100

120

140

160

-

2.0

4.0

6.0

8.0

10.0

12.0

Jan-11 Jan-12 Jan-13 Jan-14 Jan-15 Jan-16 Jan-17 Jan-18 Jan-19 Jan-20

Haynesville/Mid-Bossier Production Bcf/d

Growth

2016

2015

2014

2013

2012

2011

2010

Pre2010

Rigs

Rigs

Source: Morgan Stanley Research, EIA, DrillingInfo

Appalachia needs to grow only 1.4-1.6 Bcf/d per year through2020 to meet demand. We estimate that this can be met with thegrowth of only three producers: AR, COG, and RRC. The remainderof the basin should be able to hold production flat over the sameperiod, even at prices of $2.75 Henry Hub. Dramatic expansion of tak-eaway capacity should support narrowing of differentials and pro-vide a foundation of robust base production.

26

MCoal: Cutting Longer-Term Demand Estimates on Lower Gas Deck and Growing RenewablesSequentially higher gas prices mean more demand forcoal in 2017... Our gas and utilities team expects naturalgas pricing to average $3.10/MMBtu this year, above lastyear's average of $2.50/MMBtu, but below our previoushouse view of $3.50/MMBtu. For 2017, they have raisedtheir expectation for electricity generation from gas by 4%,which takes our coal burn lower by 3% vs. our previousforecast.

That said, 2017 is still shaping up to be a better year than 2016 for coalmining companies, with higher pricing and higher demand (coal burn up4% YoY). Based on our work, 2017 will likely be the last stronger year fordemand, and 2018 will mark the beginning of another multiyear phaseof structural weakness. Our gas and utilities team's 2018 forecast of gen-eration from gas increases by 1%. We have cut our coal burn by 1% in 2018, and we now expect a demand contraction of 3% YoY.

...However, US coal production is running 17% above last year'slevels, and if the current run rate continues, we see a modestdomestic surplus this year. Coal deficit conditions in 2016 loweredutility inventories, and helped set better pricing levels over the lastone year. However, these beneficial conditions have led to a ramp upin coal supply, and the YTD weekly coal mining rate, at 15.9 mnt, is 17%above last year's levels. If current run rate of production laststhrough the year, we see ~11 mnt of coal surplus in our 2018 marketbalance projections. We have left our coal export forecastsunchanged, and continue to think that low international prices wouldkeep exports from acting as a release valve to ease the domestic sup-ply situation.

Longer term, renewables remain the key threat to coal. Over thelast few years, low natural gas prices, environmental regulations, andthe falling cost of renewables were the three key drags on the coalindustry, in our opinion. Longer term, gas pricing is expected to staybelow $3.00/MMBtu, per our gas team's forecast, which all else equal,will shift near-term generation back toward gas vs. 2017 levels. Also,the ongoing growth in renewables and continuing coal plant retire-ments due to an ageing fleet are longer term headwinds to coal burn.

Our Utilities team expects ~84 GW of renewable capacity tocome online between 2016 and 2020, the key drag on coaldemand post 2017. They are modeling solar and wind generation

growth at a CAGR of 32% and 11%, respectively, in 2016-20. Total gen-eration capacity from solar and wind, combined with coal plantretirements, effectively displace ~73,000 GWh of 2016e coal basedelectricity generation. By 2020, electricity generation from coal, inabsolute GWhs, could fall back to pre-1980 levels.

Miners will likely see this structural decline in demand andrespond with large production cuts across all basins. Higher coalprices have been a tailwind over the last few months which has ledproduction higher, and leads us to think there will be a surplus in themarket this year as miners may take some time to curtail their pro-duction levels again. Longer term, we believe the coal industry recog-nizes that it is in a phase of structural decline, and miners have to cutproduction to continue balancing the market. This leads us to believethat we'll see cuts across all coal production basins, with Appalachiaimpacted the most.

Exhibit 56:US Coal Production is Running Above Last Year's Levels

8

10

12

14

16

18

20

22

2015-11

2015-19

2015-27

2015-35

2015-43

2015-51

2016-07

2016-15

2016-23

2016-31

2016-39

2016-47

2017-02

2017-10

Weekly

Pro

du

cti

on

(m

st)

Source: EIA, Morgan Stanley Research

Changes to Our Supply-Demand Model and Price Deck

We have again cut our coal burn numbers throughout the fore-cast horizon. Our domestic utility coal consumption forecast in2017e is 704 mnt, higher than 2016e at 675 mnt, and then scales backto 685 mnt in 2018, see Exhibit 57 . As renewables generation con-tinues to ramp up and coal plants retire, our 2020e utility coal burnforecast is now 592 mnt vs. 619 mnt previously, and down 83 mntfrom 2016.


MIn CAPP, we think thermal production will be nearly curtailed by theend of this decade, and the basin will only produce met coal. Produc-tion in NAPP and SAPP will decline over the same period. PRBremains very competitive with gas even at $2.75/MMBtu, our long-term house view, but growing renewable capacity will continue tochip away at this basin. We see a similar outcome in the ILB. Over2015-20, we are modeling cuts of 88 mnt, or 21%, in the PRB; 45 mnt,or 50%, in CAPP; and 24 mnt, or 19%, in ILB.

While the trough in coal pricing is behind us, any sustainableupside is limited, and dependent on large production cutbacks.Beyond 2017, we are modeling production cuts as mine outputshrinks to meet falling demand, and weak coal prices will need toincentivize that behavior. As a result, we see price stabilizing in thefourth quartile of the regional cost curves. This will allow most minesto keep producing, but it will limit growth and mine extension pro-jects. To factor in a lower LT gas price deck, we have modestly cut ourlong-term prices for all basins, except PRB, which we think remainscompetitive against gas. For our new price forecasts, see Exhibit 58 .Comparable spot prices for PRB, CAPP, NAPP, and ILB are $12/t, $52/t,$44/t, and $34/t, respectively. A lack of production cuts is a key riskto our price forecasts.

Exhibit 57:Changes to Our US Coal Supply-Demand Forecasts: We Have Raised2017e Production by 14 mnt

2014 2015 2016e 2017e 2018e

Production (mt)

PRB 440 418 330 370 370

CAPP 116 90 67 77 58

NAPP 135 118 106 125 110

ILB 137 124 101 110 110

Total, with others 1,000 896 739 830 788

Prior

PRB 330 370 370

CAPP 70 73 58

NAPP 107 115 110

ILB 103 110 110

Total, with others 750 816 788

Demand (mt)

Electric Power Burn 849 737 675 704 685

YE Utility Inventory 65 97 86 85 81

Prior

Electric Power Burn 672 732 694

YE Utility Inventory 94 70 63

Generation (TWh)

Total 4,094 4,078 4,078 4,075 4,088

Coal-Fired 1,586 1,350 1,242 1,295 1,260

Gas-Fired 1,127 1,333 1,381 1,292 1,283

Renewables 295 319 361 406 458

Prior

Total 4,059 4,073 4,086

Coal-Fired 1,223 1,335 1,266

Gas-Fired 1,395 1,243 1,270

Renewables 358 412 461

Source: EIA, Morgan Stanley Research Estimates. Note: CAPP refers to Central Appalachia, NAPP to Northern Appalachia, PRB to Powder River Basin, and ILB to Illinois Basin

Exhibit 58:Changes to Our US Coal Price Deck: We Have Cut Our LT Forecasts forCAPP, NAPP, and ILB

2014 2015 2016 2017e 2018e LTe

Coal Pricing ($/t)

PRB 8800 0.8# $12 $11 $9 $10 $10 $12

CAPP 12500 1.6# $59 $51 $42 $46 $48 $46

NAPP 13000 3.0# $66 $57 $41 $45 $47 $45

Illinois Basin 11800 3.4# $45 $38 $32 $35 $36 $37

Prior

PRB 8800 0.8# $10 $10 $12

CAPP 12500 1.6# $46 $48 $48

NAPP 13000 3.0# $45 $47 $47

Illinois Basin 11800 3.4# $35 $36 $38

Nat Gas Pricing ($/mmBtu)

Current Forecast $4.25 $2.62 $2.55 $3.10 $2.90 $2.75

Prior $3.45 $3.20 $3.75

Source: Bloomberg, Morgan Stanley Research Estimates. Note: CAPP refers to Central Appalachia, NAPP to Northern Appalachia, PRB to Powder River Basin, and ILB to Illinois Basin

Weaker Long-Term Global Prices Will Keep a Lid on US Coal Exports

China's NDRC is trying to put a collar around thermal coal prices.Earlier this year, the NDRC set up a narrow band for thermal coal pri-ces, with preferred pricing range of RMB 500-570/ton for benchmark5,500 kcal/kg coal, and price-altering mechanisms kicking in aboveRMB 600/t and below RMB 470/t. Chinese thermal prices are cur-rently ~1% above the top end (RMB 600/t), and the NDRC has sig-naled that it won't apply the 276-working day policy like last year. Asshoulder season kicks, we see room for Chinese coal prices to headlower in the near term. Our China team forecasts benchmark coal pri-ces at RMB 520/t in 2017 and stabilizing at RMB 470/t in 2018-19.

Our houseview calls for global benchmark thermal coal prices toweaken. Our commodity team expects spot Newcastle (FOB Austra-lia) price to average $73/t this year, decline to $65/t in 2018, and thento $62/t in 2019. Spot pricing is currently above $80/t.

Exhibit 59:CAPP Thermal Exports Are Out-of-the-Money

($40)

($30)

($20)

($10)

$0

$10

$20

$30

Jan-09

Jun-09

Nov-09

Apr-10

Sep-10

Feb-11

Jul-11

Dec-11

May-12

Oct-12

Mar-13

Aug-13

Jan-14

Jun-14

Nov-14

Apr-15

Sep-15

Feb-16

Jul-16

Dec-16

CA

PP

Exp

ort

Netb

ack

($/t

fo

b m

ine)

CAPP exports are in the money

Source: Bloomberg, Morgan Stanley Research Estimates

https://ny.matrix.ms.com/eqr/article/webapp/22b1567a-e92f-11e6-b3fe-837ed4512f41?ch=rpint#

28

MUS thermal coal exports will likely stay around 2016 levels.Europe is the prime destination for US coal, and API2 prices (CIFARA), are highly correlated to Newcastle. After hitting a peak of$90/t last year, API2 price has fallen to $71/t. US thermal coal exportsare once again out-of-the-money; see Exhibit 59 . We expect API2prices to follow the path of Newcastle, and negatively impact anyexport arbitrage. For current arbitrage levels (export vs. domesticsales), see Exhibit 60 . Based on a bearish outlook for exports, weexpect US thermal coal exports to stay below 2003 levels (seeExhibit 61 ), and not be enough to offset negative price implicationsof higher than expected production.

Exhibit 60:API2 Prices Have Recently Declined, Diminishing Incentives to ExportThermal Coal from the East. Exports from NAPP Still Appear ProfitableCoal Source Pitt 8 CAPP Rail Illinois B. PRB

Port of Export Baltimore Hampton Roads Gulf Gulf

Spec in Btu/lb GAR 13000 12500 11500 8800

Btu Premium to ARA Spec 15% 11% 2% (22%)

Destination ARA ARA ARA ARA

API 2, Delivered Europe $71 $71 $71 $71

less: Ocean Freight $5 $5 $7 $7

add: Btu differential $11 $8 $1 ($16)

FOB Port ($/tonne) $76 $73 $65 $48

FOB Port ($/short ton) $69 $67 $59 $44

less: Rail/Barge, Load $15 $20 $17 $35

less: Sulfur Discount $5 $0 $10 ($2)

FOB Mine Netback $49 $47 $32 $10.9

Current OTC Price $44 $52 $34 $11.8

Source: DTC, SNL, EIA, Morgan Stanley Research Estimates

Exhibit 61:We Expect Thermal Coal Exports to Stay Below 2003 Levels

0

20

40

60

80

100

120

140

2000

2001

2002

2003

2004

2005

2006

2007

2008

2009

2010

2011

2012

2013

2014

2015

2016e

2017e

2018e

2019e

2020e

mill

ion s

hort

tons

Met Exports

Thermal Exports

Source: Bloomberg, EIA, Morgan Stanley Research Estimates


M

Reducing price targets for our lower gas price forecast; downgrad-ing GPOR. We have reduced our long-term Henry Hub natural gasprice forecast from $3.75 to $2.75 to reflect the more robust naturalgas supply growth that we expect through 2020, particularly as asso-ciated gas production rebounds and will likely meet the majority ofdemand growth. We are lowering our price targets for the natural gasproducers by an average of 31%. We are downgrading GPOR given itschallenged outlook among the natural gas producers in this lower gasprice environment relative to our prior natural gas price deck.

Exhibit 62:Price Target Changes

Source: Morgan Stanley Research estimates

Exploration & Production: Gas Offers Weaker Risk-Reward Than OilWe see less attractive risk-reward for natural gas E&Psthan for the oil producers. The greatest challenge for thestocks as a group is the lack of visible stock-specific cata-lysts over the next several months. If the Appalachia pro-ducers were to outperform, we think it would be becauseeither 1) natural gas fundamentals improved ahead ofexpectations or 2) they caught a bid on oversold condi-tions. One of the greater challenges for the gas producersis cost inflation and higher associated gas productiongrowth tied to higher activity levels in oil plays. In a higheroil price environment, oil producers will experience costinflation, but have an offset with higher revenue. Gas pro-ducers, conversely, are likely to be squeezed on both endswith higher cost inflation and lower gas prices with higherassociated gas volumes. We optimistic on the outlook foroil fundamentals to firm up over the next several weekswhich underpins our preference for oil exposure over gas.

Exhibit 63:Gas-levered E&Ps trading around MS long-term gas price of $2.75,assuming $60 WTI and no cost inflation

$2.62 $2.70 $2.71 $2.83 $2.86

$3.08 $3.22

$0.00

$0.50

$1.00

$1.50

$2.00

$2.50

$3.00

$3.50

COG EQT AR GPOR RRC SWN ECR

Implied Long-Term Henry Hub ($/MMBtu)

Implied Price MS Long-Term Gas Price ($2.75)


Sentiment on natural gas E&Ps is weak, particularly as most inves-tors feel that there is no credible long-term bull case for natural gas.We have seen an increase in investor interest in them in recent weeks,but the investment thesis is more about the oversold conditions thanany improvement in natural gas fundamentals or stock specific cata-lysts. Year-to-date most of the stocks have behaved consistent withthe definition of a value trap. Importantly, the natural gas producersreflect a natural gas price around our long-term $2.75 Henry Hubprice deck, on the assumption that well costs are flat forever, and on$60 long-term WTI prices. We believe well costs are likely to increaseas activity picks up (particularly in oil plays) which will make the gasstocks look more expensive.

The bull case for natural gas stocks is that they are oversold andlook cheap relative to both broad markets and most sectors, in whichmost investors are generally lacking conviction. Furthermore, manyinvestors have been burned by the volatility in oil prices and preferto avoid the geopolitics involved in maintaining an oil price view. Theysee natural gas as a way to gain exposure to energy without the myr-iad complexities in the oil markets.

We continue to prefer COG and RRC the most among the Appala-chia producers for those who are bullish on gas. COG offers the high-est EBITDA sensitivity to natural gas producers of its peers and it hasan extremely strong balance sheet which makes it resilient even ifnatural gas prices weaken. Moreover, COG has exposure to asmoother FERC pipeline approval process under the Trump adminis-tration. The most visible projects which could improve COG's out-look are Atlantic Sunrise (already approved, but could startup early)and Atlantic Coast, which would improve pricing in northeast Penn-sylvania, although COG doesn't have firm capacity on the pipe. We

30

MExhibit 66:E&P NAV Sensitivity to Long-Term Gas Deck Change


Exhibit 64:2017 EBITDA Sensitivity to Gas Prices


Exhibit 65:2018 EBITDA Sensitivity to Gas Prices


find RRC attractive because of its discounted valuation for its highquality assets and sustainable growth profile even amid a lower natu-ral gas price environment.


M

Exhibit 69:2018 EV/EBITDA

4.5x 5.1x 5.2x

6.1x 6.2x 6.4x

7.2x

8.7x

0.0x

1.0x

2.0x

3.0x

4.0x

5.0x

6.0x

7.0x

8.0x

9.0x

10.0x

ECR SWN GPOR AR Average RRC COG EQT

2018 EV/EBITDA


Exhibit 67:Breakeven Gas Prices by Operator

$1.24 $1.36

$1.50 $1.51 $1.66 $1.76 $1.77 $1.84

$2.17 $2.22 $2.27 $2.28 $2.31 $2.31 $2.41 $2.47 $2.47 $2.61 $2.68 $2.77 $2.77 $2.77 $2.83 $2.87 $2.94 $2.99 $3.07 $3.13

$3.26 $3.43 $3.45

$3.80

$0.00

$0.50

$1.00

$1.50

$2.00

$2.50

$3.00

$3.50

$4.00

SC

OO

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20% IRR Breakeven Prices (Henry Hub) Assumes $60/Bbl WTI & Current Well Costs

AR CLR COG ECR EQT GPOR RRC SWN


CompsExhibit 68:2017/18/19 Assumptions: Henry Hub Averages $3.25/$3.00/$2.80

Recent PriceTicker Rating Price Target 2017 2018 2019 2017 2018 2019 2017 2018 2019 2017 2018 2019 2017 2018 2019

AR EW $22.49 $28.00 9.0x 6.1x 5.5x 3.4x 2.4x 2.2x 165% 107% 108% 26% 22% 15% 107% 97% 98%

COG EW $23.18 $26.00 10.6x 7.2x 5.5x 0.8x 0.4x 0.2x 79% 82% 81% 12% 39% 29% 13% 0% 0%

ECR EW $2.37 $2.40 5.5x 4.5x 4.8x 2.4x 2.2x 2.6x 215% 153% 171% 35% 30% 15% 71% 54% 3%

ECA EW $10.32 $15.00 8.0x 5.8x 3.8x 2.1x 1.6x 0.8x 126% 106% 66% -7% 23% 12% 67% 20% 9%

EQT EW $57.30 $59.00 8.9x 8.7x 8.3x 1.8x 2.1x 2.3x 165% 146% 125% 12% 18% 12% 56% 17% 2%

GPOR UW $16.23 $13.00 6.5x 5.2x 5.5x 2.7x 2.4x 2.6x 162% 154% 117% 53% 38% 5% 65% 34% 0%

RRC EW $27.68 $33.00 9.0x 6.4x 5.0x 3.3x 2.4x 1.8x 115% 102% 101% 37% 23% 26% 80% 21% 0%

SWN UW $7.56 $7.00 6.7x 5.1x 5.6x 2.6x 2.2x 2.4x 103% 94% 100% 3% 10% 2% 80% 38% 15%

Average 8.0x 6.1x 5.5x 2.4x 2.0x 1.9x 141% 118% 109% 21% 25% 15% 68% 35% 16%Median 8.5x 6.0x 5.5x 2.5x 2.2x 2.2x 144% 106% 104% 19% 23% 13% 69% 28% 2%

EV to EBITDAX Net Debt to EBITDA Capex vs. DCF Production Growth Hedged


Exhibit 70:2019 EV/EBITDA

4.8x 5.0x 5.5x 5.5x 5.5x 5.6x 5.7x

8.3x

0.0x

1.0x

2.0x

3.0x

4.0x

5.0x

6.0x

7.0x

8.0x

9.0x

ECR RRC COG GPOR AR SWN Average EQT

2019 EV/EBITDA


32

MExhibit 71:YE18 Leverage

0.4x

2.0x 2.1x 2.2x 2.2x

2.4x 2.4x 2.4x

0.0x

0.5x

1.0x

1.5x

2.0x

2.5x

3.0x

COG Average EQT ECR SWN RRC AR GPOR

YE18 Net Debt to EBITDA


Exhibit 72:YE19 Leverage

0.2x

1.8x 2.0x

2.2x 2.3x 2.4x

2.6x 2.6x

0.0x

0.5x

1.0x

1.5x

2.0x

2.5x

3.0x

COG RRC Average AR EQT SWN GPOR ECR

YE19 Net Debt to EBITDA



M

production from the emerging STACK and SCOOP resource plays inthe Anadarko Basin in Oklahoma to the US Gulf Coast and Southeastmarkets and is expected to consist of ~200 milles of 36 inches main-line pipeline from the STACK and SCOOP and provide deliveries toBennington, Oklahoma, the TexOk hub near Atlanta, Texas, and thePerryville Hub near Tallulah, Louisiana. Midship has already securedcommitments from Cheniere, Devon Energy Corp., Marathon OilCorp., and Gulfport Energy Corp. While the project's economics andChieniere's stake remain unknown, the new pipeline is expected todrive Cheniere's cost of gas even lower offering additional upside.The project is targeting a startup in early 2019.

Exhibit 73:US LNG producers can benefit from lower US gas prices

Asia Europe

Gas cost 2.75$ 2.75$

Gas lost for fuel 9.0% of HH 0.25$ 0.25$

O&M expense 0.24$ 0.24$

Maintanance cost 0.17$ 0.17$

Pipeline Cost 0.16$ 0.16$

ROI @ 10% 2.43$ 2.43$

Liquefaction cost 3.00$ 3.00$

Freight Cost 2.07$ 0.92$

Total Delivered Cost 8.06$ 6.92$

required price above HH 5.31$ 4.17$

Cash brekeven 5.63$ 4.49$

required price above HH 2.88$ 1.74$

Breakeven Cost for New FIDs


LNG Exporters: Lower for Longer US Gas Prices Improves Export Economics Low US gas prices improves LNG export economics;raising Cheniere's PT to $55 from $50. US LNG exporterslike Cheniere are the key beneficiaries of the structuralpressure on long-term US gas prices, making their volumemore competitive in the global market. US LNG exporterswould be able to source gas at even lower cost increasingtheir margins on existing liquefaction. We are thereforeraising our PT for Cheniere to $55 (from $50) based on theDCF of the existing 7 trains taking into account: 1) the exist-ing 20-year SPA agreements for 87% of its capacity at 9%discount rate, 2) our revised long-term Henry Hub price of$2.75/MMBtu, and 3) assuming all the remaining 13%uncontracted volume is sold at an average long-term priceof $8.5/MMbtu (same as before) discounted at 15%.Although, our base case only takes into account the 7 exist-ing trains, we estimate that Cheniere's CCL3 and SPL6trains could be profitable even at Brent prices below $60/bbl. The signing of new SPA agreements that would sup-port further expansion could add at least $10/share to ourvaluation for each additional train.

US LNG export projects become more competitive, increasingpotential for new FIDs. Lower cost of gas would make it easier forUS Henry Hub linked export projects to compete with oil-linked vol-ume, allowing them to sign profitable long-term SPA agreementsthat would lead to new FIDs. We estimate that based on our revised$2.75/MMBtu long-term Henry Hub prices, new US liquefactionwould need Asian LNG prices of ~$8/MMBtu to be sanctioned, whichbased on today's slope of 12-13% corresponds to $60-67/bbl Brentprice range vs our Energy team's LT forecast of $75/bbl. The econom-ics become even more attractive for LNG liquefaction projects whohave access to low-cost basins in Appalachia or Permian and SCOOP-STACK basins as well as expansion projects that can benefit from theexisting infrastructure and have lower capital cost. There are cur-rently 15 US LNG export projects with increased likelihood to reachFID of which Cheniere's two expansion projects and Golden Passseem to have the highest probability.

MIDSHIP pipeline project offers access to low cost STACK/SCOOP. Cheniere announced earlier this month that it has launchedan open season for its up to 1.4 Bcf/d Midcontinent Supply HeaderInterstate Pipeline (MIDSHIP). The MIDSHIP pipeline will connect

34

MExhibit 75:Lower US gas would make it easier for new US export projects to reachFID

Milestone reached or about to be reached

Progress is being made but details are still not finalized

Little meaningful progress on reaching milestone

Source: WoodMackenzie, Morgan Stanley Research

Exhibit 74:Lower US gas prices make it profitable for Cheniere to sell its uncon-tracted volume and increases the likelihood of new FIDs that can offermaterial upside

Cheniere Energy Inc. (LNG) SOTP value

### 7 8 9 10 11

3.6 30 18.0 16.0 11.5 3.0 -3.8

4.2 35 20.2 17.5 13.0 4.5 -2.3

4.8 40 23.1 20.4 16.3 7.8 0.9

5.4 45 23.1 20.4 16.3 7.8 0.9

6.0 50 23.1 20.4 16.3 7.8 0.9

6.6 55 37.6 38.2 43.5 44.4 46.6

7.2 60 41.6 44.7 51.9 54.6 58.4

7.8 65 46.4 52.4 61.8 66.7 72.3

8.4 70 50.4 59.0 70.2 76.9 84.1

9.0 75 55.2 66.7 80.1 88.9 98.0

9.6 80 59.2 73.3 88.5 99.2 109.8

10.2 85 63.9 81.0 98.4 111.2 123.7

10.8 90 68.0 87.6 106.8 121.4 135.6

11.4 95 72.0 94.2 115.3 131.7 147.4

12.0 100 76.7 101.9 125.1 143.7 161.3

12.6 105 81.5 109.6 135.0 155.7 175.2

13.2 110 85.5 116.2 143.5 166.0 187.0

Asia

n L

NG

Price (

$/b

bl)

Bre

nt

($/b

bl)

# of Trains


M

1. Attractive valuations & strategic optionality. Cash flowremains strong despite weak commodity prices, with free cashflow to equity yields in the 20-45% range. For pure-play independ-ent power producers and certain diversified utilities, we see stra-tegic action as a potential path to unlock value. Private valuationsfor merchant power assets, particularly natural gas plants, are ata material premium to those currently implied by the public mar-ket.

2. Tax reform could improve earnings and cash flow. We expecttax reform to be a key focus later in 2017, and expect a reductionin Federal corporate tax rates to be the most likely outcome.Diversified utilities and IPPs are beneficiaries of lower taxes, as itwould improve earnings and cash flow for the unregulated busi-nesses of many stocks in the group.

3. Rising interest rates. A key headwind across all deregulatedpower markets has been low cost construction of new gas powerplants, a theme that is supported by the availability of low-costfinancing. Higher interest rates increase the revenue requirementfor new generation, a positive for incumbent power plant owners.

4. Stable power price outlook, with more upside drivers thandownside risk. We believe the power market could begin to out-perform gas, reversing the underperformance seen over the last1-2 years. Forwards price in little volatility, limiting downside inour view while leaving the potential for upside to power and sparkspreads driven by retirements, summer heat or cold winterweather. We also continue to forecast an improvement in localgas prices in the Marcellus/Utica region, a constructive dynamicfor regional power prices.

Diversified Utilities & IPPs: Pockets of Opportunity in a Low Gas WorldWe maintain our Attractive industry view of the Diversified Utilities & IPPs (Independent Power Producers) givena number of positive themes driving stocks in 2017 despite downward revisions to our natural gas price forecasts.We are reflecting our commodities team's forecast and lowering our long-term gas price assumption from $3.75 to $2.75/MMBtu for Henry Hub and from $3.00 to $2.50/MMBtu for the PJM market region. Although this update results in down-ward revisions to our price targets in the space, we continue to see a constructive backdrop for the group with severalpositive themes present this year:

Preferred Merchant Power Stocks: Dynegy (DYN - OW) and NRGEnergy (NRG - OW)

In the context of lower gas price forecasts, the following are keydebates we are focused on in merchant power:

l Potential positive surprises in the upcoming PJM capacityauction: Investor expectations are very bearish, with RTO pricingexpectations in the $100-110/MW-day range with only a modestbreakout in EMAAC. Though our RTO expectations are only mod-estly above consensus, we see the potential for upside surprisesin EMAAC and ComEd, where we see potential for breakouts rela-tive to RTO with both potentially pricing in the $150-200/MW-day range.

l Low gas prices could push additional states to implementmeasures to support struggling nuclear plants, but thesewould not be incrementally negative for other merchantpower companies. Financial support measures for nuclear plantshave been implemented in NY and IL, and should serve as a partialoffset to the negative impact of our outlook for lower natural gasprices. With further financial pressure from continued low gas pri-ces, we think there could be greater urgency to enact these meas-ures in additional states as well. While this likely extends the livesof plants that otherwise would shut down, we view this as theremoval of a bullish scenario (upside to energy and capacity fromplant retirements) rather than an incremental negative to the cur-rent market outlook.

l Stock sensitivities to further gas price downside. We believeinvestors will be focused on understanding which power stocksare most sensitive to further downside in gas prices. Our esti-mates indicate EXC faces the most downside at -10.4% in (EPS/EBITDA) for a $0.50 move in gas price from $3.00 to $2.50. CPNis least sensitive by our analysis, with the same move leading toa 3% decline in (EPS/EBITDA).


36

M

Reducing price targets on lower long-term gas price forecasts.We are incorporating our commodities team's forecast and loweringour long-term gas price assumption from $3.75 to $2.75/MMBtu forHenry Hub and from $3.00 to $2.50/MMBtu for the PJM marketregion. This change results in 1% to 20% declines in our price targetsacross the group, with NRG's valuation the most sensitive to terminalgas prices. DYN continues to represent the largest valuation discon-nect in our view, as it still shows significant upside to our new PT.

Merchant Power Stock Implications The reduction in our long-term gas forecast leads to PT reductions across our merchant power coverage, but we still see meaning-ful valuation dislocations in the group, robust cash flow generation, and a constructive setup overall for merchant power-relatedequities in 2017. This year we predict a more stable power price backdrop, with more upside drivers than downside risk and amarket environment where power prices could outperform gas, all positive indicators for stocks. Merchant power stocks alsotrade at 20-40%+ free cash flow to equity yields using the current forward curve by our estimates. At the same time, our analysisshows that in order to make several merchant power stocks "fairly valued" at current levels, we would need to see long-run gasprices across the entire US of below $2.50/MMBtu, a terminal level which is too bearish, in our view. Overweight-rated Dynegy(DYN) continues to screen most favorably in the group, and remains our top pick.

Exhibit 76:Lowering PTs Across Many Merchant Power-Exposed Stocks, WithNRG the Most Impacted

Old PT

Price

Change New PT % Change % Upside

NRG $25 ($5) $20 -20% 10%

DYN $18 ($3) $15 -17% 113%

CPN $13 ($2) $11 -15% 3%

EXC $40 ($3) $37 -8% 3%

FE $42 ($2) $40 -5% 28%

PEG $51 ($2) $49 -4% 9%

D $82 ($3) $79 -4% 1%

NEE $158 ($2) $156 -1% 18%


Some merchant stocks continue to reflect sub-$2.50 gas andtrade at robust, and persistent, free cash flow yields. Our analysisshows that in order to make several merchant power stocks "fairlyvalued" at current levels, we would need to see long-run gas pricesacross the entire US of below $2.50/MMBtu, a terminal level whichis too bearish, in our view. EW-rated CPN and OW-rated NRG are theoutliers, as these stocks still reflect $3.10-4.00/MMBtu long-run gas.Furthermore, merchant power stocks now trade in a narrow bandaround 20% free cash flow-to-equity yields, with DYN being theexception at 45%. We continue to believe that cash flow to equity isthe most important metric in valuing merchant generation compa-nies, and that the ultimate measure of a company’s worth is theamount of cash the company generates for its shareholders. Forinvestment grade companies, which includes EXC (ExGen) and PEG

Exhibit 77:Several Merchant Stocks Trade at 18-45% FCF-Equity Yields...

0%

5%

10%

15%

20%

25%

30%

35%

40%

45%

50%

DYN (OW) PEG (EW) NRG (OW) CPN (EW) EXC (EW)

2017-19 Average MSe FCF/Equity Yield

Source: Morgan Stanley Research. Only includes stocks with the most meaningful merchant exposure, and excludes those that are exiting the business.

(PSEG Power), we view +20% free cash flow-to-equity yields asreflecting enticing value. For non-investment grade companies,which includes the three IPPs: DYN, NRG, and CPN, we see 20% FCF-equity yields as moderately attractive. DYN is the standout of thegroup, now trading at a FCF-equity yield of 45%, a level we viewas a beckoning entry point.

Exhibit 78:… and Some Reflect Sub-$2.50 Gas Prices

Source: Morgan Stanley Research. Note, we show PEG on this chart, but our analysis shows there is no gas price low enough to make the stock "fairly valued" at current levels. Only includes stocks with the most meaningful merchant exposure, and excludes those that are exiting the business.


MMany companies in the merchant power space have taken steps toreduce their sensitivity to changes in natural gas prices by "gasifying"their fleet over the last several years. That said, gas prices remain ameaningful driver for the space.

From a sensitivity to earnings perspective, NRG is most leveredto changes in gas prices, in our view. Generally speaking, most mer-chant power companies are less sensitive to declines in gas pricesfrom current levels than they would be to a similar magnitudeincrease. This is because the correlation between natural gas andpower prices begins to break down in very low gas price environ-ments, as coal increasingly becomes the marginal fuel source.

Exhibit 79:Merchant Companies that Have "Gasified" Experience Notably LowerSensitivities to Changes in Natural Gas Prices

-15%

-10%

-5%

0%

5%

10%

15%

EXC

(EW)

NRG

(OW)

DYN

(OW)

PEG

(EW)

CPN

(EW)

Terminal EPS / EBITDA Impact From $0.50 Move in Gas % Change from $0.50 Decrease to $2.50

% Change from $0.50 Increase to $3.50

Source: Morgan Stanley Research. Only includes stocks with the most meaningful merchant exposure, and excludes those that are exiting the business. PEG based on disclosed gas sensitivity adjusted for hedges.

EXC: Negative revisions to long-term commodity prices offsetEXC’s successful execution on ZECs and improving utilityreturns; overall, we see a more balanced view on risk-rewardgiven the stock’s outperformance relative to peers since the2016 presidential election. Lowering PT from $40 to $37, down-grading from OW to EW. The company has successfully achievednuclear support in several jurisdictions and executed on their plan toimprove earned returns at their utilities – an action that we believenow merits a premium multiple on the utility. However, we can’tignore the 10% relative outperformance versus the UTY since theelection. Our $37 price target now applies a lower discount rate onthe ZEC payments given the stability of these cash flows, and alsoapplies a premium multiple to utility earnings. These positive revi-sions are offset by our weaker outlook on natural gas prices, a leverto which Exelon is more sensitive given its large baseload nuclearfleet. Our new PT implies 3% of remaining upside and, as such, webelieve the risk-reward looks balanced at current levels.

M

Third, Morgan Stanley's oil and gas outlooks underpin animproved backdrop for NGL's. Together with Morgan Stanley'srecently published oil forecast, a lower for longer gas forecastimplies a higher oil/gas ratio, a primary indicator of NGL profitability.Domestic petchem producers should have a global competitiveadvantage, consuming ethane, and competing with higher cost nap-tha (oil)-based crackers overseas.

On the downside, weaker producers may need continued supportvia MVC adjustments or tariff reductions on cost of service pipelines.These developments will likely be more intermittent than system-atic, however. Contract specifics, basin locations, and producer finan-cial strength will each play a role in setting this up as a potential prob-lem on a individual systems.

Our Overweight thesis on EQT Midstream (EQM) is somewhatweaker in the out years of 2020+, but the importance to EQM of theadditional EBITDA from major projects (MVP) and potential consoli-dation in the basin keeps us interested. With the new gas forecast ourE&P team sees EQT's 2016-2020 growth trajectory as26%/11%/20%/11%/2%, a lowered trajectory from26%/14%/15%/13%/13%, which results in approximately 10% lowerproduction in 2020. Though 2020 is lower with this forecast, thenext three years at EQT are very similar to prior levels given currentactivity and continued improvements in well efficiencies such thatthe volume underpinnings for our EQM call are intact.

Midstream ImplicationsWith both the demand and supply of gas projected higher than in our previous models, the midstream sector shouldbenefit from the higher volumes as well as in three additional ways: greater pipe and processing project growth,reduced recontracting risk, and better NGL fundamentals.

First, volumes transported and processed will be higher. Pipesshould be operating fuller with potential need for more pipeline pro-jects but certainly demand for more interconnects to handle thechanging flows. New gas pipeline takeaway will be needed from thePermian and SCOOP/STACK basins as oil production rises and possi-bly from the Marcellus Utica in the 2020/21 timeframe if productionthere continues to rise. In addition, more interconnects with currentand anticipated LNG projects are likely, primarily in the Texas Gulfmarket from Mexico to Louisiana. Connecting Gulf Coast demandwith Texas gas will be made difficult to track from the outside asexcess capacity on Texas intrastate networks can swing volumes withonly small amounts of interconnect capital spending. Lastly, thecadence of new processing capacity adds could be sped up to handlethe growing volumes in the Permian and Marcellus/Utica. Large gaspipeline-oriented firms include SEP, KMI, WMB, ETP, BWP, and TEP.Unaffilitated G&Ps likely benefitting from the growing volumeswould include TRGP, OKE, and DCP.

Second, recontracting risks are lessened on the margin. Recoveryin output from the Haynesville should lessen the price and volumerecontracting risks in that basin and others with challenged econom-ics in recent quarters. Areas such as the Haynesville are being set upfor more activity at least in some parts of the play as acreage owner-ship changes, producer economics are reset and fresh capital is avail-able to drill.

In addition, moving gas further East from Texas across Louisiana andinto the South is a likely competitor for additional gas out of theNortheast. Florida customers, for example, may want diversity ofsupply and several "out-of-basin" pipes such as those from the Hay-nesville, could conceivably be used as "thru-basin" pipes enroute tothe South and East. Many are working hard to redefine pipes withboth excess capacity and contracts expiring in 2018-20. Trackingdevelopments will be somewhat difficult as some of the underutil-ized pipes now are intrastate systems with excess capacity in, forexample, Texas or Louisiana; information is less available on thesesystems.

38



MChemicals Agriculture / Fertilizers

Natural gas is the principal raw material used in the nitrogen fer-tilizer production process and typically accounts for over half oftotal production costs. North American nitrogen companies havebeen competitively advantaged given their access to low-cost natu-ral gas. Using MSe revised forecast for natural gas rather than thefutures curve would impact our EPS estimates as follows: CF: 2017+$0.02 (+5.7%); 2018 +$0.10 (+16.1%); AGU: 2017 +$0.05 (+1.0%);2018 +$0.05 (+0.9%); POT: 2017 +$0.01 (+1.6%); 2018 +$0.01(+1.3%). We note that: (1) CF is a nitrogen pure play, though it hashedged 45% of its 2017 natural gas requirements at $3.28 and 10%of its 2018 natural gas requirements at $3.21, therefore partially lim-iting the impact of natural gas price volatility; (2) Agrium is a diversi-fied global crop input and agricultural services provider with nitro-gen representing ~19% of 2017E EBITDA; and (3) Potash Corp. is oneof the largest global fertilizer companies by capacity with nitrogenrepresenting ~29% of 2017E EBITDA. Our estimates - and we believeconsensus - uses the futures curve. Please see our below EPS sensitiv-ity for CF Industries, Agrium, and Potash Corp. based on natural gasprices changes versus the futures curve.

The US remains a major importer of nitrogen fertilizer, withapproximately 50% of total nitrogen demand sourced frominternational markets. Recall that in the late 1990s and early2000s the US was disassembling plants and shipping the compo-nents to lower cost natural gas markets. However, the shale gasboom combined with structurally higher planted corn acreage madeUS nitrogen economics more compelling. Despite strong profitabil-ity since 2007, no new North American projects were announceduntil 2012 with producers historically citing: (1) Difficulty in obtainingappropriate state and federal permits for expansion projects; and (2)The inability to lock in long-term natural gas contracts as reasons fornot pursuing greenfield projects.

Total expected capacity additions from projects that are cur-rently under construction total ~3.7 million mt. Among the~11.8M mt of additional capacity announced to come online in NorthAmerica, we see ~3.7M mt as being highly probable given that theseprojects are currently under construction or completed. We wouldclassify an additional ~3.4M mt of capacity additions as possible asthese projects have a signed ENC contract, though they are stillawaiting financing. The remaining ~4.6M mt of capacity projectseither do not have financing or can be considered preliminary at this

Exhibit80:CF Industries EPS Sensitivity

CF % Change to MS Base Case EPS Forecasts

EPS

2017E 2018E 2019E

($1.00) 121% 112% 87%

($0.50) 61% 56% 43%

$0.00 0% 0% 0%

$0.50 -61% -56% -43%

$1.00 -121% -112% -87%Gas P

rice C

han

ge

($/m

mb

tu)

Source: Company Data, Morgan Stanley Research estimates.

Exhibit81:Agrium EPS Sensitivity

Agrium % Change to MS EPS Forecasts

EPS

2017E 2018E 2019E

($1.00) 6% 6% 6%

($0.50) 3% 3% 3%

$0.00 0% 0% 0%

$0.50 -3% -3% -3%

$1.00 -6% -6% -6%Gas P

rice C

han

ge

($/m

mb

tu)


Exhibit82:Potash Corp. EPS Sensitivity

Potash Corp. % Change to MS EPS Forecasts

EPS

2017E 2018E 2019E

($1.00) 9% 9% 8%

($0.50) 5% 4% 4%

$0.00 0% 0% 0%

$0.50 -5% -4% -4%

$1.00 -9% -9% -8%Gas P

rice C

han

ge

($/m

mb

tu)


point (i.e., on hold, permitting issues, or in bankruptcy proceedings).To be clear, we do not include either the ~3.4M mt or ~4.6M mt ofcapacity in our supply forecast. While we believe those projects witha signed ENC contract are likely at a later stage, financing still remainsan issue and these projects may not secure the necessary capital tostart construction given the tighter funding environment, escalatingconstruction costs, and lower expected returns.

40

M

Petrochemicals

We model a 10c/gal premium to fuel-value (FV) for ethane in2H17+ as new ethylene startups drive incremental ethanedemand. Ethane is the most widely used feedstock for US ethyleneproduction, which when oversupplied tends to be priced at its fuelvalue equivalent (i.e. the btu value of "rejecting" or leaving ethane inthe natural gas stream). This has generally been the past few yearsas the US shale boom has driven ethane supply growth well in excessof petrochemical demand. We expect this relationship to persistthrough the wave of new ethylene startups, but expect a modest pre-mium to FV to occur in order to cover the transportation and tariffcosts required to bring currently "rejected" ethane to market.

Our estimated premium to FV is less than many bears and indus-try consultants contend (in some cases up to 30c/gal above FV)as we believe that: (i) the likely ramp time for incremental crackersto come online will be longer; (ii) sunk cost economics associatedwith bringing currently rejected ethane to market means lower incre-mental variable costs; (iii) significant flex capacity exists to use bothpropane and butane instead of ethane when it is more economical;(iv) EIA ethane inventories are higher than they've been in a decade,and do not account for privately held stocks which are similarly ele-vated, and (v) a supply response may take place in both the Permianand (South Central Oklahoma) from the confluence of higher naturalgas prices, a modest ethane price premium to natural gas, and poten-

Exhibit83:North America Project DetailsNorth America Urea Capacity Expansion Projects

Capex

Capacity Estimate Year Target

Company / Project (M mt) ($M) Ann. Date Project Status

Agrium Borger II 0.6 $756 2014 2017 Completed

BioNitrogen - Taylor County & Hendry County, FL 0.3 $600 2012 2021+ Seeking Financing; Filed for Bankruptcy

CF Port Neal II 1.2 $2,600 2012 2016 Completed

Cronus - Tuscola, Illinois 1.3 $1,900 2013 2021+ EPC Contract Signed; Awaiting Financial Close

Dakota Gasification Company Beulah 0.4 $500 2012 2017 Under Construction

Eurochem - Louisiana 1.2 $1,500 2013 2021+ Selected site; Awaiting Board Approval

Fatima / Midwest Fertilizer - Mount Vernon, IN 0.4 $2,700 2012 2021+ EPC Contract Signed; Awaiting Financial Close

FNA Fertilizer Limited - Belle Plaine, SK 1.2 $2,200 2012 2021+ Seeking Financing; Permit Issue Delays

Koch Enid II 0.8 $1,300 2013 2017 Under Construction

La Coop Fed/IFFCO - Quebec, CA 1.2 $1,720 2012 2021+ On Hold; Seeking Financing

Northern Plains Nitrogen - Grand Forks, ND 0.7 $2,500 2013 2021+ Seeking Financing

OCI Iowa 0.8 $2,250 2012 2017 Under Construction

Ohio Valley Resources - Rockport, IN 1.0 $1,200 2012 2021+ EPC Contract Signed; Awaiting Financial Close

Summit Power Group - Odessa, TX 0.7 $2,500 2010 2021+ EPC Contract Signed; Awaiting Financial Close

Completed / Under Construction 3.7 $7,406

Completed / Under Construction / EPC Contract Signed 7.2 $15,706

All Projects Total 11.8 $24,226


Exhibit 84:We expect ethane prices to continue to be driven by "fuel value," thoughanticipate a modest premium to emerge as we move through the bal-ance of the decade.

1.00

2.00

3.00

4.00

5.00

6.00

7.00

8.00

Jan-1

3

Ju

l-1

3

Jan-1

4

Ju

l-1

4

Jan-1

5

Ju

l-1

5

Jan-1

6

Ju

l-1

6

Jan-1

7

Ethane ($/mmbtu) Natural Gas ($/mmbtu)

Source: IHS, ICIS, Morgan Stanley Research

tially more associate gas from incremental shale oil production post-OPEC. To be clear, we do not rely on meaningfully higher oil pricesin our base case scenario. That said, we do acknowledge that there isshort-term upside risk to our estimated FV premium as the ethanemarket may need to adjust to incremental petrochemical and exportdemand before a supply response takes place.


M

Exhibit 86:EIA ethane inventories are at all-time highs, though do not include pri-vate stocks, which are similarly elevated and should help to mitigatemarket shocks as the wave of new gulf coast steam crackers comeonline.

0

20

40

60

80

100

120

140

160

-

10,000

20,000

30,000

40,000

50,000

60,000

Ja

n-0

0

No

v-0

0

Sep

-01

Ju

l-0

2

May-0

3

Mar-

04

Ja

n-0

5

No

v-0

5

Sep

-06

Jul-0

7

Ma

y-0

8

Ma

r-09

Jan-1

0

No

v-1

0

Sep

-11

Jul-1

2

Ma

y-1

3

Ma

r-14

Jan-1

5

No

v-1

5

Sep

-16

Ethane Inventory (000's bbls, LHS) Ethane-USGC (c/gal, RHS)

10,0

20,0

30,0

40,0

50,0

60,0

Etha


Exhibit 85:The premium that we expect to FV will likely be necessary to bring cur-rently "rejected" ethane to market. That said, we suspect the incremen-tal cost to bring rejected supply to market is likely less than many bearscontend.

0

200

400

600

800

1000

1200

1400

1600

1800

2000

Feb

-10

May-1

0A

ug

-10

No

v-10

Feb

-11

May-1

1A

ug

-11

No

v-11

Feb

-12

May-1

2A

ug

-12

No

v-12

Feb

-13

May-1

3A

ug

-13

No

v-13

Feb

-14

May-1

4A

ug

-14

No

v-14

Feb

-15

May-1

5A

ug

-15

No

v-15

Feb

-16

May-1

6A

ug

-16

No

v-16

Eth

an

e S

up

ply

M B

PD

Extraction Rejection


Exhibit 87:Notably, EIA ethane inventories are currently well above historicallyimplied relationship with ethane prices (as well as frac spreads), sug-gesting that we may likely see inventory draws without a commensu-rate impact on pricing.

R² = 0.6737

-

10,000

20,000

30,000

40,000

50,000

60,000

0 50 100 150

Ethane USGC Price (c/gal)

Ethane Inventory (000's bbls, Monthly)

Jan 2000 - Dec 2016

Jan 2016 - Dec 2016


We expect incremental ethylene startups and export facilities todrive cumulative incremental ethane demand of 223mbpd,490mbpd, and 699mpbd by YE17, YE18, and YE19, respectively.These estimates assume that all ethylene expansions come onlinewithin currently expected timelines, and that capacity runs at 70%utilization during the first year of mechanical completion. This alsofactors in 70% demand of export facilities, which could arguablyprove uneconomical at current oil prices and therefore release eth-ane into the petrochemicals market.

42

MExhibit 88:We expect incremental ethylene startups and export facilities to drive cumulative incremental ethane demand of 223mbpd, 490mbpd, and699mpbd by YE17, YE18, and YE19, respectively.

Incremental US Ethylene Crackers (mechanical completion, mm lbs)

Company City 2017e 2018e 2019e 2020e 2021e

Chevron Phillips Cedar Bayou 827 2,480 - - -

Dow Freeport 827 2,480 - - -

Dow Plaquemine 551 - - - -

Equistar Corpus Christi 400 400 - - -

ExxonMobil Baytown - 3,307 - - -

FPC USA Point Comfort - 690 2,066 - -

Indorama Ventures PCL Lake Charles - 463 463 - -

LACC LLC Lake Charles - - - 2,205 -

Oxy/Mexichem JV Ingleside 908 304 - - -

SASOL Lake Charles - - 3,417 - -

Shell Chemical Monaca - - - - -

Shin-Etsu Plaquemine - - 1,102 - -

Westlake Lake Charles 121 - - - -

Westlake Calvert City 49 49 - - -

Total Incremental Nameplate Capacity (mm lbs) 3,683 10,173 7,048 2,205 -

Cumulative New Nameplate Capacity (mm lbs) 3,683 13,856 20,904 23,108 23,108

Effective Incremental US Ethylene Production (mm lbs)

2017e 2018e 2019e 2020e 2021e

Assumed utilization in first year of mechanical completion 70% 70% 70% 70% 70%

Assumed utilization after first year of mechanical completion 95% 95% 95% 95% 95%

Production from facilities in 1st yr of completion 2,578 7,121 4,934 1,543 -

Cumulative production from facilities after 1st yr of completion - 3,499 13,163 19,859 21,953

Cumulative Incremental US Ethylene Production (mm lbs) 2,578 10,620 18,097 21,402 21,953

Cumulative Incremental US Ethylene Production via Ethane1

2,322 9,891 17,273 20,521 21,049

Cumulative Incremental US Ethylene Production via Propane1

256 729 823 881 903

Cumulative Incremental Ethane Demand (mbdp)

Cumulative Incremental Ethane Demand (mbpd)2

66 280 489 581 596

Enterprise (Houston; mbpd)3

140 140 140 140 140

Sunoco Logistics (Marcus Hook; mbpd)4

18 35 35 35 35

Kinder Morgan (Utopia East; mpbd)5

35 35 35 35

Cumulative Exports (mbpd)3

158 210 210 210 210

Total Cumulative Incremental Ethane Demand 223 490 699 791 806

1. Assumes Dow's new capacity, LYB's Corpus Christi, and WLK's Calvert City run 80/20 ethane/propane

2. 0.434 gallons of ethane consumed per lbs of ethylene

3. Assumes EPD's 200mbpd ethane terminal is 70% utilized

4. Assumes Sunoco's 275mbpd Mariner E 2 terminal is 100% propane; Mariner E1 70mbpd terminal becomes 100% ethane

5. Assumes Kinder Morgan's 50mbpd E terminal is 70% utilized

Source: IHS, Morgan Stanley Research estimates


M

We expect a reduction in ethane rejection to supply 400-500mpbd of incremental ethane demand at only a modest pre-mium to FV (~10c/gal). We estimate that ~574mbpd of ethane wasrejected in December, which compares to a peak of ~770mbpd inAugust, and a 2016 trough of ~465mpbd in June. The fact that we'veseen ethane rejection fluctuate +/-300mbpd this year on only a mod-estly positive premium to FV/frac spread (4-6c/gal) gives us confi-dence that this capacity remains available at a similar premium to fuelvalue. Indeed, the observed elasticity in ethane rejection has beenmore substantial than many bears and industry consultants contend,which we believe relates to the prevalence of sunk cost economicsand contractual commitments driving incremental extraction at fracspreads below incremental nominal tariff and transportation fees.

Exhibit 89:We estimate that ~574mbpd of ethane was rejected in December,which compares to a peak of ~770mbpd in August, and a 2016 troughof ~465mpbd in June.

-6.0

-4.0

-2.0

0.0

2.0

4.0

6.0

8.0

0.0

100.0

200.0

300.0

400.0

500.0

600.0

700.0

800.0

900.0

Jan

-15

Mar-

15

May-1

5

Jul-

15

Sep

-15

No

v-15

Jan

-16

Mar-

16

May-1

6

Jul-

16

Sep

-16

No

v-16

Eth

an

e S

up

ply

M B

PD

~574 MBPD ethane rejection in December

Rejection Frac Spread

Source: Envantage, EIA, Morgan Stanley Research

Exhibit 90:We attribute the +/-300mbpd fluctuation in ethane rejection over thelast two years on only a modestly positive premium to FV/frac spread(4-6c/gal) to the prevalence of sunk cost economics and contractualcommitments.

y = -21.765x + 652.37

R² = 0.5249

400.0

450.0

500.0

550.0

600.0

650.0

700.0

750.0

800.0

-6.0 -4.0 -2.0 0.0 2.0 4.0 6.0 8.0

Eth

an

e R

eje

ctio

n (

mb

pd

)

Ethane Frac Spreads (c/gal)

Ethane Rejection vs. Frac Spread (Jan '15 -

December '16)

Source: Envantage, EIA, Bloomberg, Morgan Stanley Research

Exhibit 91:Fractionation fees and nominal tariff and freight fees suggest that fuel-value (FV) premiums need to rise as high as $0.20/gal to extract 400-500mpbd of currently rejected ethane to market (the blue line below).However, the blue line ignores the sunk cost economics that are often-times associated with transporting ethane, which allowed ethanerejection levels to fluctuate +/-300mbpd this summer on only a mod-estly positive premium to FV (i.e., frac spread of 4-6c/gal). The yellowline illustrates the scenario in which all transportation and tariff fees aresunk costs. The reality is likely that incremental costs fall somewherein between the blue and yellow lines, which is part of why we choose tomodel a 10c/gal premium to FV for ethane in 2H17+.

$0.00

$0.05

$0.10

$0.15

$0.20

$0.25

$0.30

$0.35

$0.40

0 50 100 150 200 250 300 350 400 450 500 550 600Ethane Supply (MBbls/d)

Premium to FV to Incentivize E&P Ethane Recovery ($/gal)

Premium to FV Premium to FV (ex. Transport)

2018 Cumulative Incremental Ethane Demand Plus Exports (490 MBbls/d)

LA Gulf Coast

New Mexico Midcon

TX Inland Appalachia

Rockies

Upper Midwest

Rockies Midcon

Appalachia New Mexico

TX Inland TX Gulf Coast

2018 Cumulative Incremental Ethane Demand (280 MBbls/d)

LA Gulf Coast

2018 Cumulative Incremental Ethane Demand Less Propane Switching (171 MBbls/d)

Source: Envantage, Platts, Morgan Stanley Research estimates

We also expect incremental propane substitution to displace100mpbd+ of incremental ethane demand at similarly modestpremiums to FV (~<10c/gal). We believe that propane currentlyaccounts for only 16% of US ethylene production, and that the UScapacity base could flex to produce 20% of ethylene using propanewith minimal incremental investment (equates to ~100mpbd of eth-ane). This process would begin as propane cash costs become moreeconomical relative to ethane cash costs, which at present wouldbegin with ~5c/gal higher ethane prices, all else equal. If ethane priceswere to rise even further in relation to propane prices, we'd expecteven more propane substitution, given that most US ethane crackerswere originally repurposed from naphtha, and therefore have intrin-sic structural capabilities to handle incremental by-products. Wetherefore assume 25% of ethylene production could consume pro-pane in our bull case scenario, which would displace another~100mpbd of ethane demand. Note however, that while US crackershave the ability to produce ~35% of ethylene using propane on a the-oretical basis, there would likely be challenged in supplying the pro-pane to these facilities and/or other logistical constraints that wouldrequire incremental investment and time to mitigate. The impact ofincremental propylene and other by-product production associatedwith switching to propane from ethane on their respective marketbalances should also be kept in mind - i.e., more propane cracking

44

M

would lead to more propylene production, which could drive propyl-ene oversupply, lower prices, and therefore increase propane cashcosts.

Exhibit 92:We also expect incremental propane substitution to displace 100mpbd+ of incremental ethane demand at similarly modest premiums to FV(~<10c/gal).

Flex Ethylene Capacity Scenarios

2016 US E feedslate Flexed US E feedslate scenarios

Bear Case Base Case Bull Case

Ethylene Production % by Feedstock

Ethane 70% 63% 53%

Propane 16% 20% 25%

Butane 8% 10% 15%

Naphtha 5% 5% 5%

Other 2% 2% 2%

Total 100% 100% 100%

Ethylene Production by Feedstock (mm lbs)

Ethane 40,646 36,806 30,964

Propane 9,176 11,684 14,606

Butane 4,707 5,842 8,763

Naphtha 2,776 2,776 2,921

Other 1,118 1,314 1,168

Total 58,422 58,422 58,422

Incremental Ethane Substitution

Substituted Ethane Produced Ethylene (mm lbs) - (3,840) (9,682)

Incremental Ethane Demand (mbpd)1

- (109) (274)

1. 0.434 gallons of ethane consumer per lbs of ethylene

Source: IHS, Morgan Stanley Research estimates

We continue to model the FV component of Lyondell and Dow'sethane costs off of the futures curve, to which Morgan Stanley'srevised natural gas outlook represents modest upside. Our DOWand LYB models currently assume natural gas prices of $3.29 and$3.07 for 2017 and 2018, respectively, which compare to our mostrecent MSe estimates of $3.10 and $2.90. If we were to use MSe esti-mates, our EPS forecasts for both DOW and LYB would increase byless than 1% in both 2017 and 2018.

Exhibit93:DOW EPS Sensitivity (via ethane)

DOW % Change to MS Base Case EPS Forecasts

EPS

2017E 2018E 2019E

($1.00) 4% 4% 4%

($0.50) 2% 2% 2%

$0.00 0% 0% 0%

$0.50 -2% -2% -2%

$1.00 -4% -4% -4%

Gas P

rice

Ch

an

ge

($/m

mb

tu)

Source: Company Data, Morgan Stanley Research estimates

Exhibit94:LYB EPS Sensitivity (via ethane)

LYB % Change to MS Base Case EPS Forecasts

EPS

2017E 2018E 2019E

($1.00) 4% 4% 4%

($0.50) 2% 2% 2%

$0.00 0% 0% 0%

$0.50 -2% -2% -2%

$1.00 -4% -4% -4%

Gas P

rice

Ch

an

ge

($/m

mb

tu)

Source: Company Data, Morgan Stanley Research estimates


M

As expected, coal trends improved in 2H16 and are robust thus farin 2017, with coal carloads outperforming at Western vs. Easternrails. One quarter into 2017, Class I rails' coal trends are up +16.5% YoYaccelerating from a decline of 2% YoY in 4Q16 (See Exhibit 95 ).Recent trends are consistent with our view that very easy YoY compari-sons and higher natural gas prices bode well for coal volumes. Thus farthis year, the magnitude of coal volume increases is greater at Westernthan Eastern rails (note we need to adjust for a utility coal contractshift from CSX to NSC to determine true underlying trends). In thewest, UNP and BNSF’s coal volumes are +17% and +18% YoY YTD,respectively, while in the east, we estimate CSX and NSC's utility coalvolumes are flattish to up low-single digits YoY YTD after adjusting forthe market share shift (See Exhibit 96 ).

We originally expected strength in utility coal volumes to lastthroughout 2017 and possibly spilling over to 1H18. However, itappears that we overestimated the coal bounce. Underlying driv-ers of coal shipments have been softer than anticipated. Natural gasprices increased sequentially throughout 2016, reaching an averageprice of $3.40 in 4Q16 (+44% YoY) and declined sequentially to~$3.00 on average in 1Q17 (+50% YoY 1Q17). Natural gas prices thusfar this year have not been as high as our expectations of ~$3.50mainly due to relatively mild winter weather which has kept coalinventory levels elevated. 2016/2017 winter was milder than normalas cumulative population weighted gas heating degree days(GWHDDs) were ~15% below the 30-year normal over the Novem-ber-February period, with the most extreme mild temperatures arriv-ing in February. As such, 2016 ended the year with utility coal inven-tory of ~164mt, or roughly 90 days of burn vs. initial expectations of115mt or 60 days of burn, representing a more "normal" levels. UNP'smanagement noted that PRB inventory levels are still above 5-yearaverage and we'd note that the pace of inventory drawdown appearsto be decelerating. Similarly, at a recent investor conference, NSC'smanagement guided to the low end of their 1Q17 utility coal guidancegiven warmer weather in the South. While we still expect a short-lived rebound in coal volumes in 2017, the magnitude and dura-tion may be shorter than originally expected.

Rails: Coal Window of Opportunity NarrowingA dead coal bounce. The one-off coal bounce that we wereawaiting this year may come in lighter than we originallyexpected. As laid out earlier in this report, coal economicsare not particulary robust as natural gas prices appearunlikely to reach the previously forecasted ~$3.50 leveland coal destocking remains slow. We are lowering our util-ity coal volume estimates for UNP and the Eastern rails(CSX/NSC) though we maintain a relatively positive viewon Western (PRB) over Eastern (Illinois Basin/Appalachian)coal. While we acknowledge that Rail stocks are not likelyto trade on fundamentals for a while, given the halo ofmacro/policy tailwinds at all rails and added activism haloat the Eastern rails, our downgrade of coal expectations isa real, near-term catalyst vs. the other longer term hopetrades. We believe the most exciting topline story withinRails is now the return of Crude-by-Rail 2.0 driving earningsat the Canadian rails (see Canadian Crude: Pipeline Bottle-necks Coming; Time for Crude-by-Rail 2.0? (10 Mar 2017)).

Revisiting the Rail Coal opportunity in 2017. Last June and Decem-ber, we published two collaborative reports with Morgan Stanley’sCommodities, Power & Utilities and Metals & Mining teams in whichwe discussed the opportunity for a short-term rally in coal shipmentsin 2017/18 due to higher NG prices (see here and here). We noted thepotential for a wide range of coal outcomes in 2017 – up to 25% YoYincrease in coal shipments depending on severity of winter weatherand level of natural gas prices. Among the rails, we expected UNP tosee the earliest and most benefit, as it is most exposed to PRB coal,which has a lower break-even price vs. natural gas at $3.00-3.50 com-pared to Appalachian coal at $3.50-4.00, which the Eastern rails(CSX/NSC) are more exposed to. In this section, we discuss the U.S.rails’ year-to-date coal trends and our Commodities, Power & Utilitiesand Metals & Mining teams’ updated outlooks, and discuss its impli-cations on UNP, CSX, and NSC.

https://ny.matrix.ms.com/eqr/article/webapp/a63e3032-d802-11e6-81d6-6f51e3822ad5?ch=rpint

https://ny.matrix.ms.com/eqr/article/webapp/a63e3032-d802-11e6-81d6-6f51e3822ad5?ch=rpint

https://ny.matrix.ms.com/eqr/article/webapp/366ecc8a-2687-11e6-81bf-fc96bc66805e?ch=esig

https://ny.matrix.ms.com/eqr/article/webapp/df5b74c8-b585-11e6-addd-5083e71245e2?ch=rpint

46

M

Exhibit 96:1Q17 MSe Western vs. Eastern Rails Coal Traffic YoY % Change

Reported Adjusted

UNP 16.5% N/A

BNSF (not covered by MS) 10.0% N/A

CSX Total Domestic Coal -9.1% -0.3%

NSC Utility Coal 12.0% 2.3%

Source: Company data, Morgan Stanley Research, Note: We assume ~110 coal tons per carload and utility coal contract shift from CSX to NSC is ~6 million tons annually, evenly distributed among the quar-ters. This implies that CSX and NSC's domestic coal volumes are flattish to up LSD YoY in 1Q17

Exhibit 95:U.S. Class I Rails Coal Traffic YoY % Change

Source: AAR, Morgan Stanley Research

Exhibit 97:UNP Coal Carloads

Source: Company Data, Morgan Stanley Research

Exhibit 98:CSX Coal Carloads


Exhibit 99:NSC Coal Carloads


Exhibit 100:Nat Gas Pricing and Powder River Basin / Northern Appalachian Break-even

$1.5

$2.0

$2.5

$3.0

$3.5

$4.0

$4.5

$5.0

$5.5

2014 2015 2016 2017 2018

$/m

mB

tu

PRB Break-even ($3.00-$3.50)

NAPP Break-even ($3.50-$4.00)

Source: Thomson Reuters, Morgan Stanley Research Estimates, Note: break-even lines represent mid-point of rail mgmt. commentary

Our Commodities, Power & Utilities and Metals & Mining teamsupdated their NG and coal forecasts which will impact our coalvolume and earnings estimates for UNP, CSX, and NSC. Our Com-modities, Power & Utilities team forecasts (a) Natural gas prices of$3.10-3.15 for the rest of 2017 with a peak of $3.30 in 4Q17, muchlower than original expectations for a $3.55 peak, (b) After reachinga high point in 4Q17, nat gas prices are forecasted to fall to $2.70-2.95throughout 2018, averaging around $2.90 for the year, and (c) Long-term natural gas prices to settle around $2.75. Additionally, our Met-als & Mining team's work suggests 2017 will likely be the last strongeryear for coal demand and 2018 will mark the beginning of anothermulti-year phase of structural weakness. Key points from their workinclude: (a) ~4% bounce in total coal demand in 2017 (vs. ~8% previ-ously) and a ~5% CAGR decline from 2017 to 2020, with 2020 coaldemand ~10% below 2016's levels, and (b) total coal production todecline at a ~6% CAGR from 2017 to 2020 to match falling demand.


MLower natural gas prices make utility coal shipment economicsless attractive. UNP has very little export coal exposure, so weassume that all of UNP's coal carloads are utility coal. On the otherhand, 70-80% of the Eastern Rail's coal exposure is utility while alarge portion of the rest is export coal. We are lowering UNP's totalcoal and the Eastern Rails' utility coal volume estimates for2017/18/19 (see Exhibit 101 ). Here are our assumptions:

l 2017: We are lowering UNP's 2017 coal volumes to +7.5% YoYfrom +9% YoY as our Commodities, Power & Utilities teamnow expects nat gas prices at $3.10-3.15 in 2017. Though PRBcoal still breaks even at these prices, the range falls at the lowend of UNP management's preferred range of $3.00-3.50. Weare modeling high teens YoY coal volume growth in 1H17given very easy YoY comps and low-single digits growth in2H17 as comps become more difficult. We are modeling -6%and +7% YoY change in total coal volumes for CSX and NSC,respectively, which is distorted by CSX losing a utility coalcontract to NSC. Adjusting for the market share shift (whichwe estimate ~6M annual tons or ~54K carloads), we are mod-eling +0-1% total coal volume growth for the Eastern railsdriven by stronger than expected export coal (up double dig-its YoY for both rails). Specifically looking at the Eastern rails'utility coal tonnage, we are modeling ~5% YoY declines in2017 after adjusting for the market share shift.

Exhibit 101:UNP Total Coal and CSX/NSC Utility Coal Carloads YoY % Change Esti-mates

2017 2018 2019 2017 2018 2019

UNP 7.6% -1.0% -6.0% 9.0% 1.0% -6.0%

CSX Total Domestic -13.3% -4.4% -5.0% -5.6% 2.3% 0.8%

CSX Adj. -4.8% 2.9%

NSC Utility 4.2% -5.6% -6.1% 10.0% -8.3% -2.6%

NSC Adj. -5.0% 0.8%

Updated Previous

Source: Company Data, Morgan Stanley Research Estimates; Note: We assume utility coal contract shift from CSX to NSC is ~6 million tons annually

l 2018: We are lowering UNP's 2018 coal volumes to -1% YoYvs. previously +1% YoY as PRB coal becomes less competitiveat $2.90 nat gas vs. previous house view of $3.20. We expectEastern rails' total coal volumes to decline high-single digitsYoY in 2018. Specifically looking at the Eastern rails' utilitycoal tonnage, we are modeling mid-single digits YoY declinesin 2018.

l 2019: We continue to model UNP's 2019 coal volumes down6% YoY and lower the Eastern rails' total coal volumes (andutility coal volumes) to ~5% YoY declines vs. previously low-single digits declines. Our long-term thesis that coal and ener-gy-related end markets remain in secular decline is intact asour Commodities, Power & Utilities team's new long-term natgas forecast of $2.75 would pressure coal demand. Further-more, environmental regulations, the retirement of agingpower plants, and falling costs of renewables also drive astructural shift in the US generation mix away from coal andover to gas, wind, and solar.

Our UNP and NSC 2018 and 2019 EPS estimates and price targetsdecrease 2-3%. Though CSX's 2019 EPS decreases 2% from the lowercoal volume assumption, CSX's price target remains unchanged dueto non-coal related factors. Note that CSX announced last monththat it is reducing over 20% of its management work force which isexpected to deliver at least $175M in annual productivity savings. Weexpect this initiative to more than offset coal headwinds in 2017 and2018 (See Exhibit 102 and Exhibit 103 ).

Exhibit 102:MS EPS Estimates vs. Consensust

Prev MS

Est.

Cur MS

Est.Cons. Est

MS vs.

Cons.

MS vs.

Cons.

Prev MS

Est.

Cur MS

Est.Cons. Est

MS vs.

Cons.

MS vs.

Cons.

Prev MS

Est.

Cur MS

Est.Cons. Est

MS vs.

Cons.

MS vs.

Cons.

Rails Rails Rails

CSX $2.03 $2.06 $2.04 1% - CSX $2.10 $2.10 $2.40 (12%) ▼ CSX $2.32 $2.28 $2.85 (20%) ▼NSC $6.05 $6.04 $6.15 (2%) ▼ NSC $6.50 $6.42 $6.87 (7%) ▼ NSC $7.05 $6.86 $7.52 (9%) ▼UNP $5.74 $5.64 $5.62 0% - UNP $6.24 $6.06 $6.33 (4%) ▼ UNP $6.66 $6.45 $7.05 (9%) ▼

2017FY

Ticker Ticker

2018FY

Ticker

2019FY

Source: Thomson Reuters, Morgan Stanley Research Estimates

Exhibit 103:Price Target Changes

Old PT New PTStock

Price

New %

Upside

Rails

CSX $37 $37 $46 (20%)

NSC $74 $72 $111 (35%)

UNP $99 $97 $104 (7%)

Ticker

TMF

Source: Thomson Reuters, Morgan Stanley Research Estimates; Note: stock price as of 3/24/17 close

48

MValuation Methodology & RisksExhibit104:Merchant Power Valuation Methodology & Risks

Valuation

Company Ticker Methodology Risks

American Electric Power AEP We value AEP via a SOTP. We value the regulated utility by applying the regulated group P/E multiple to 2018

Utility EPS and a DCF analysis for the merchant business. For our DCF we use a 6.9% WACC, 3% Risk-Free

Rate, and 1.5% Terminal Growth Rate.

1) Failure to execute on growth endevours; 2)

Weaker than expected sales growth; 3) Execution

of long-term contracts at the merchant business

Dominion Resources D We value D via a SOTP. We value the regulated utility by applying a 5% premium regulated group P/E multiple to

2018 Utility EPS to account for above average growth, a DCF analysis for the merchant business, and an EV /

EBITDA multiple on the gas business. For our DCF we use a 6.8% WACC, 3% Risk-Free Rate, and 1.5%

Terminal Growth Rate.

1) Gas and power price changes for merchant

power; 2) DOE/FERC approval delays; and 3)

Midstream gas market deterioration in OH/PA,

which could negatively impact producer servicing

contracts for the Blue Racer JV, 4) recovery in

power demand growth, 5) Cove Point and Atlantic

Coast Pipeline project execution.

Entergy Corp. ETR We value ETR via a SOTP. We value the regulated utility by applying the regulated group P/E multiple to 2018

Utility EPS and a DCF analysis for the merchant business. For our DCF we use a 9% WACC and 3% Risk-Free

Rate.

1) Indian Point is forced to shut down by NY State;

2) Load growth does not materialize; 3) Low

Marcellus/Utica gas prices spread to NY and New

England

Exelon Corp. EXC Derived from our base case and driven by a 2018 P/E for utilities and a DCF analysis for generation and energy

supply (ExGen). For our DCF we use an 8% WACC, 3% Risk-Free Rate, And 1.5% Terminal Growth Rate.

1) Natural gas and power prices decline further.

EXC is the most sensitive diversified utility to

natural gas prices on our math; 2) PJM capacity

prices in the May '16 auction could be

disappointing; 3) Additional states implementing

carbon cap and trade programs. Additional carbon

regulation would benefit EXC's large nuclear fleet

FirstEnergy FE Derived from our base case and driven by a 2018e P/E for utilities and DCF analysis for merchant power and

retail assuming a spin-merger of the merchant business, using a ~6.9% WACC

1) Changes in gas and power prices could affect

EPS meaningfully; every $1/mmBtu move in gas

impacts open EPS by ~15-20%; 2) Potential for

management to remain committed to owning

merchant generation, which could trigger larger

equity issuance needs than currently disclosed

Public Service Enterprise Group PEG We value PEG via a SOTP. We value the regulated utility by applying the regulated group P/E multiple to 2018

Utility EPS and use a DCF analysis for the merchant business. For our DCF we use a 7.2% WACC, 3% Risk-Free

Rate, and 1.5% Terminal Growth Rate.

1) Higher energy and capacity could be a positive

for shares as the company’s Power business is levered to commodities; 2) Strategic activity is not

reflected in our valuation or estimates. But

unregulated M&A has shown to be a positive in the

sector due to considerable cost synergies

AES Corp AES We value AES using a relative 2018 P/E valuation for US regulated utilities, DCF analysis for merchant power,

and market prices for publicly listed Brazilian subsidiaries. For our DCF we use a 10x FCF terminal multiple and a

12% discount rate.

1) Better- or worst-than-expected regulatory

outcomes; 2) Stronger- or weaker-than-expected

commodity prices; 3) Better- or worse-than-

expected foreign exchange rates

Calpine CPN We value CPN using a DCF analysis and assume a long-term natural gas price of $3.75/mmBtu and EMAAC

capacity prices of $225/MW-day. We also assume Texas peak margins rise to $25/MWh longer-term, which is

our estimate of replacement value for new generation in Texas. For our DCF we use a 6.8% WACC, 3% Risk-

Free Rate, and 1.5% Terminal Growth Rate.

1) Market tightness in Texas is not realized due to

weaker than expected load growth, increased

renewables penetration, and/or additional

construction of new conventional generation; 2)

Further renewables penetration in California

decreases long-run margin potential of CPN’s gas-

fired assets and its large Geysers geothermal

asset

Dynegy DYN We value DYN via a SOTP, assigning separate values for total GasCo,ENGIE, CoalCo, and IPH. We assume a

long-term gas price of $3.75/mmBtu, long-run capacity prices in-line with recent results, and long-run total energy

and capacity margins in-line with the replacement value for new generation in PJM and New England.

1) Changes in gas, power and capacity prices; 2)

Additional environmental regulations driving higher

coal capex requirements and/or shut-downs

NRG Energy NRG We value NRG using a DCF analysis and assume a long-term natural gas price of $3.75/mmBtu and EMAAC

capacity prices of $225/MW-day. We also assume Texas peak margins rise to $25/MWh longer-term, which is

our estimate of replacement value for new generation in Texas. For our DCF we use a 7.3% WACC, 3% Risk-

Free Rate, and 1.5% Terminal Growth Rate.

1) Weak gas prices; 2) Lack of improvement in

Texas power prices; 3) Execution risk on achieving

operational merger

synergies



MExhibit105:Exploration & Production Valuation Methodology & Risks

Valuation


Antero Resources Corp. AR Our price target of $28 is based on our NAV, which uses a 10% discount rate and equates to 9.8x 2017e EBITDA.

AR trades at 9.0x 2017e EBITDA vs peers at 8.0x.

1) Well performance 2) Wider gas differentials 3)

Commodity prices 4) Service Cost Inflation

Cabot Oil & Gas Corp. COG Our price target of $26 is based on our NAV, which uses a 10% discount rate and equates to 11.8x 2017e

EBITDA. COG trades at 10.6x 2017e EBITDA vs peers at 8.0x.



Eclipse Resources Corp. ECR Our price target of $2.40 is based on our NAV, which uses a 10% discount rate and equates to 5.5x 2017e

EBITDA. ECR trades at 5.5x 2017e EBITDA vs peers at 8.0x.



Encana Corp. ECA Our $15.00 price target is derived from a 50% weighting of our 8.0x Target Multiple and 50% weighting of 1.0x our

est. risked NAV. Our target implies the shares will trade at 10.5x 2017 EVDACF. ECA trades at 8.0x 2017e

EBITDA vs peers at 8.0x.



EQT Corp. EQT Our price target of $59 is based on our NAV, which uses a 10% discount rate and equates to 9.9x 2017e EBITDA.

EQT trades at 8.9x 2017e EBITDA vs peers at 8.0x.



Gulfport Energy Corp. GPOR Our price target of $13 is based on our NAV, which uses a 10% discount rate and equates to 6.5x 2017e EBITDA.

GPOR trades at 6.5x 2017e EBITDA vs peers at 8.0x.



Range Resources Corp. RRC Our price target of $33 is based on our NAV, which uses a 10% discount rate and equates to 10.1x 2017e

EBITDA. RRC trades at 9.0x 2017e EBITDA vs peers at 8.0x.



Southwestern Energy Co. SWN Our price target of $7 is based on our NAV, which uses a 10% discount rate and equates to 6.5x 2017e EBITDA.

SWN trades at 6.7x 2017e EBITDA vs peers at 8.0x.




Exhibit 106:Freight Transportation Valuation Methodology & Risks

Valuation


CSX CSX We use a 10-year DCF assuming 5.9% WACC and terminal cash flow perpetual growth rate of 1.5% (implying an

exit EBITDA multiple of 9.0x). Our DCF valuation implies a fwd P/E of 17.6x, which is above CSX's historical 5-yr.

average, reflecting investor optimism about CSX's ability to deliver operating leverage as volumes come back and

cost savings/productivity gains.

1) Operating metrics bring up the rear of the group;

2) Higher than average exposure to challenged end

markets. Coal has already been a big headwind; 3)

Sentiment/valuation at all time high

Norfolk Southern Corp. NSC We use a 10-year DCF assuming 7.4% WACC and terminal cash flow perpetual growth rate of 1.5% (implying an

exit EBITDA multiple of 6.0x). Our DCF valuation implies a fwd P/E of 11.2x, which is below NSC's historical avg.

given our cautious outlook on rails.

1) Cost cutting potential exists but may not be as

large as some believe; 2) NSC will continue to

experience topline headwinds given coal exposure;

3) Valuation is unattractive.

Union Pacific Railroad UNP We use a 10-year DCF assuming 7.1% WACC and terminal cash flow perpetual growth rate of 1.5% (implying an

exit EBITDA multiple of 9.0x). Our DCF valuation implies a fwd P/E of 16.0x, which is below UNP's historical 5-

year avg. reflecting secular growth headwinds.

1) As end markets become more pressured and

inflation increases, UNP may see difficulty in

achieving inflation+ pricing; 2) If coal gets worse

into 2017 due to cool weather or continued natural

gas supply, UNP could be hit worse than Eastern

Rails; 3) Panama Canal expansion could hurt UNP

more than other Rails.


Exhibit 107:Midstream Valuation Methodology & Risks

Valuation


EQT Midstream Partners LP EQM • We value Midstream firms with a combination of P/DCF, EV/EBITDA multiples, distribution discount models

(DDM), yield targets, sum-of-the-parts, and exchange ratios to derive our price targets and valuation ranges.

For LPs we weight P/DCF at 40%, EV/EBITDA at 20%, DDM 20%, and yield at 20%. Our Overweight rating is

predicated on exposure to attractive Marcellus and Utica shale midstream infrastructure development through a

producer parent and attractive relative valuation.

• Risks include multiple compression from less visible organic growth, commodity prices, project

delays, and customer concentration.


50

MMorgan Stanley provided a fairness opinion to the Board of Directors of Pepco Holdings, Inc. (”Pepco”) in relation to their definitive agreementto combine Pepco with Exelon Corporation, as announced on April 30, 2014. The proposed transaction is subject to the approval of Pepco share-holders, required regulatory approvals, and other customary closing conditions. This report and the information provided herein is not intendedto (i) provide voting advice, (ii) serve as an endorsement of the proposed transaction, or (iii) result in the procurement, withholding or revocationof a proxy or any other action by a security holder. Pepco has agreed to pay fees to Morgan Stanley for its financial advisory services, includingtransaction fees. Please refer to the notes at the end of the report.

Morgan Stanley is acting as financial advisor to The Dow Chemical Company ("Dow") in relation to its proposed merger with E.I. DuPont deNemours & Company ("DuPont"), as announced on December 11th, 2015. The proposed transaction is subject to approval by the shareholdersof both DuPont and Dow, regulatory approval and other customary closing conditions. This report and the information provided herein is notintended to (i) provide voting advice, (ii) serve as an endorsement of the proposed transaction, or (iii) result in the procurement, withholding orrevocation of a proxy or any other action by a security holder. Dow has agreed to pay fees to Morgan Stanley for its financial services, includingfees that are contingent upon the consummation of the transaction. Please refer to the notes at the end of the report.

Morgan Stanley & Co. LLC (“Morgan Stanley”) is acting as financial advisor to ENGIE in relation to the proposed sale of ENGIE’s United StatesFossil Portfolio to the JV to be formed between Dynegy, Inc. and Energy Capital Partners, and the sale of its Hydro Assets to Public Sector PensionInvestment Board, as announced on 25 February 2016. ENGIE has agreed to pay fees to Morgan Stanley for its financial services. Please referto the notes at the end of the report.

Morgan Stanley is providing financing services to Dynegy, Inc. ("Dynegy") in relation to the proposed acquisition of ENGIE’s United States FossilPortfolio through the JV to be formed with Energy Capital Partners as announced on 25 February 2016. The transaction is subject to regulatoryand other customary closing conditions.

Morgan Stanley is acting as financial advisor to CF Industries Holdings, Inc. (“CF”) in connection with its definitive agreement with OCI N.V.(“OCI”) under which CF will combine with OCI’s European, North American and Global Distribution businesses as announced on August 6, 2015.The proposed transaction requires the approval of shareholders of both CF and OCI and is subject to receipt of certain regulatory approvalsand other customary closing conditions. CF has agreed to pay transaction fees to Morgan Stanley for its financial advice, including fees thatare contingent upon the consummation of the proposed transaction. Please refer to the notes at the end of the report. Morgan Stanley isengaged to provide financial advisory services to NRG Energy Inc. in connection with certain strategic initiatives. There is no guarantee that anyspecific transaction or initiative will be consummated. Please refer to the notes at the end of this report.

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RobinsonWorldwide Inc., Cabot Oil & Gas Corp., California Resources Corp, Calpine Corp., Canadian National Railway Co., Canadian Natural Resources Ltd, CanadianPacific Railway Ltd., Celanese Corp., Cenovus Energy Inc, CF Industries, Cheniere Energy Inc., Cimarex Energy Co., Cobalt International Energy Inc, ConchoResources Inc., ConocoPhillips, Continental Resources Inc., CSX Corporation, DCP Midstream LP, Devon Energy Corp, Dominion Resources Inc, DynegyInc., E.I. DuPont de Nemours & Co., Eastman Chemical Co, Echo Global Logistics Inc, Eclipse Resources Corp, Enable Midstream Partners LP, EnbridgeEnergy Partners LP, Encana Corp., Energy Transfer Equity, LP, Energy Transfer Partners LP, EnLink Midstream LLC, EnLink Midstream Partners LP,Entergy Corp, Enterprise Products Partners LP, EOG Resources Inc, EP Energy Corp, EQT Corp., Exelon Corp, FedEx Corporation, First Solar Inc,FirstEnergy Corp, Genesee & Wyoming Inc., Gulfport Energy Corp, Hannon Armstrong, Heartland Express Inc., Hess Corporation, Hub Group Inc, HuskyEnergy Inc, Intrepid Potash, Israel Chemicals Ltd., J.B. Hunt Transport Services Inc., Kansas City Southern, Kinder Morgan Inc., Knight Transportation Inc.,Landstar System Inc, LyondellBasell Industries N.V., Magellan Midstream Partners LP, Marathon Oil Corporation, MEG Energy Corp, Midcoast EnergyPartners LP, Monsanto Company, Mosaic Company, Newfield Exploration Co., NextEra Energy Inc, Noble Energy Inc., Norfolk Southern Corp., NRG EnergyInc, Oasis Petroleum Inc., Occidental Petroleum, Old Dominion Freight Line Inc, Oneok Inc., ONEOK PARTNERS LP, Parsley Energy Inc, Phillips 66Partners LP, Pioneer Natural Resources Co., Plains All American Pipeline LP, Platform Specialty Products Corporation, Plug Power Inc., Potash Corp ofSaskatchewan Inc, PPG Industries Inc., Public Service Enterprise Group Inc, Range Resources Corp., Saia, Inc., SemGroup Corp, Sherwin-Williams Co.,Southwestern Energy Co, Spectra Energy Partners LP, Suncor Energy Inc, Sunoco Logistics Partners LP, Sunoco LP, SunPower Corp, Sunrun Inc, TallgrassEnergy Partners LP, Targa Resources Corp., Tesoro Logistics LP, The Dow Chemical Co., TPI Composites Inc., Trinseo S.A., Union Pacific Corp., UnitedParcel Service, Werner Enterprises, Western Gas Equity Partners, L.P., Western Gas Partners LP, Whiting Petroleum Corporation, Williams Companies, Inc,
MORGAN STANLEY RESEARCH 51 59

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Williams Partners LP, XPO Logistics, Inc..Within the last 12 months, Morgan Stanley has received compensation for products and services other than investment banking services from AES Corp.,Albemarle Corporation, American Electric Power Co, Anadarko Petroleum Corp, Apache Corp., Axalta Coating Systems Ltd, Boardwalk Pipeline Partners LP,Buckeye Partners LP, Calpine Corp., Canadian Pacific Railway Ltd., Celanese Corp., Cheniere Energy Inc., Concho Resources Inc., ConocoPhillips, CSXCorporation, Devon Energy Corp, Dominion Resources Inc, Dynegy Inc., E.I. DuPont de Nemours & Co., Eastman Chemical Co, Echo Global Logistics Inc,Enbridge Energy Partners LP, Encana Corp., Energy Transfer Equity, LP, Energy Transfer Partners LP, Entergy Corp, Enterprise Products Partners LP, EOGResources Inc, EP Energy Corp, Exelon Corp, FirstEnergy Corp, Genesee & Wyoming Inc., Hess Corporation, Israel Chemicals Ltd., J.B. Hunt TransportServices Inc., Kansas City Southern, Kinder Morgan Inc., LyondellBasell Industries N.V., Magellan Midstream Partners LP, MEG Energy Corp, MonsantoCompany, Mosaic Company, MPLX LP, NextEra Energy Inc, Noble Energy Inc., Norfolk Southern Corp., NRG Energy Inc, Occidental Petroleum, OldDominion Freight Line Inc, Oneok Inc., Plains All American Pipeline LP, Platform Specialty Products Corporation, Potash Corp of Saskatchewan Inc, PPGIndustries Inc., Public Service Enterprise Group Inc, SemGroup Corp, Spectra Energy Partners LP, Suncor Energy Inc, Sunoco Logistics Partners LP,Tallgrass Energy Partners LP, Targa Resources Corp., The Dow Chemical Co., Union Pacific Corp., United Parcel Service, Western Gas Equity Partners,L.P., Western Gas Partners LP, Williams Companies, Inc, Williams Partners LP, XPO Logistics, Inc..Within the last 12 months, Morgan Stanley has provided or is providing investment banking services to, or has an investment banking client relationship with,the following company: AES Corp., Agrium Inc., Air Products and Chemicals Inc., Albemarle Corporation, American Electric Power Co, Anadarko PetroleumCorp, Antero Midstream Partners LP, Antero Resources Corp, Apache Corp., ArcBest Corp, Axalta Coating Systems Ltd, Boardwalk Pipeline Partners LP,Buckeye Partners LP, C.H. Robinson Worldwide Inc., Cabot Oil & Gas Corp., California Resources Corp, Calpine Corp., Canadian National Railway Co.,Canadian Natural Resources Ltd, Canadian Pacific Railway Ltd., Celanese Corp., Cenovus Energy Inc, CF Industries, Cheniere Energy Inc., Cheniere EnergyPartners L.P., Cimarex Energy Co., Cobalt International Energy Inc, Concho Resources Inc., ConocoPhillips, Continental Resources Inc., CSX Corporation,CVR Partners, LP, DCP Midstream LP, Devon Energy Corp, Diamondback Energy Inc, Dominion Midstream Partners LP, Dominion Resources Inc, DynegyInc., E.I. DuPont de Nemours & Co., Eastman Chemical Co, Echo Global Logistics Inc, Eclipse Resources Corp, Enable Midstream Partners LP, EnbridgeEnergy Partners LP, Encana Corp., Energy Transfer Equity, LP, Energy Transfer Partners LP, EnLink Midstream LLC, EnLink Midstream Partners LP,Entergy Corp, Enterprise Products Partners LP, EOG Resources Inc, EP Energy Corp, EQT Corp., Exelon Corp, FedEx Corporation, First Solar Inc,FirstEnergy Corp, Genesee & Wyoming Inc., Gulfport Energy Corp, Hannon Armstrong, Heartland Express Inc., Hess Corporation, Hub Group Inc, HuskyEnergy Inc, Intrepid Potash, Israel Chemicals Ltd., J.B. Hunt Transport Services Inc., Kansas City Southern, Kinder Morgan Inc., Knight Transportation Inc.,Landstar System Inc, LyondellBasell Industries N.V., Magellan Midstream Partners LP, Marathon Oil Corporation, MEG Energy Corp, Midcoast EnergyPartners LP, Monsanto Company, Mosaic Company, MPLX LP, Newfield Exploration Co., NextEra Energy Inc, Noble Energy Inc., Norfolk Southern Corp.,NRG Energy Inc, Oasis Petroleum Inc., Occidental Petroleum, Old Dominion Freight Line Inc, Oneok Inc., ONEOK PARTNERS LP, Parsley Energy Inc,Phillips 66 Partners LP, Pioneer Natural Resources Co., Plains All American Pipeline LP, Platform Specialty Products Corporation, Plug Power Inc., PotashCorp of Saskatchewan Inc, PPG Industries Inc., Public Service Enterprise Group Inc, Range Resources Corp., Saia, Inc., SemGroup Corp, Sherwin-WilliamsCo., Southwestern Energy Co, Spectra Energy Partners LP, Suncor Energy Inc, Sunoco Logistics Partners LP, Sunoco LP, SunPower Corp, Sunrun Inc,Tallgrass Energy Partners LP, Targa Resources Corp., Tesoro Logistics LP, The Dow Chemical Co., TPI Composites Inc., Trinseo S.A., Union Pacific Corp.,United Parcel Service, Valero Energy Partners LP, Werner Enterprises, Western Gas Equity Partners, L.P., Western Gas Partners LP, Whiting PetroleumCorporation, Williams Companies, Inc, Williams Partners LP, XPO Logistics, Inc..Within the last 12 months, Morgan Stanley has either provided or is providing non-investment banking, securities-related services to and/or in the past hasentered into an agreement to provide services or has a client relationship with the following company: AES Corp., Agrium Inc., Air Products and ChemicalsInc., Albemarle Corporation, American Electric Power Co, Anadarko Petroleum Corp, Antero Resources Corp, Apache Corp., Axalta Coating Systems Ltd,Boardwalk Pipeline Partners LP, Buckeye Partners LP, C.H. Robinson Worldwide Inc., Cabot Oil & Gas Corp., California Resources Corp, Calpine Corp.,Canadian National Railway Co., Canadian Natural Resources Ltd, Canadian Pacific Railway Ltd., Celanese Corp., Cenovus Energy Inc, CF Industries,Cheniere Energy Inc., Cheniere Energy Partners L.P., Concho Resources Inc., ConocoPhillips, Continental Resources Inc., CSX Corporation, DCP MidstreamLP, Devon Energy Corp, Dominion Resources Inc, Dynegy Inc., E.I. DuPont de Nemours & Co., Eastman Chemical Co, Echo Global Logistics Inc, EclipseResources Corp, Enable Midstream Partners LP, Enbridge Energy Partners LP, Encana Corp., Energen Corp., Energy Transfer Equity, LP, Energy TransferPartners LP, EnLink Midstream LLC, EnLink Midstream Partners LP, Entergy Corp, Enterprise Products Partners LP, EOG Resources Inc, EP Energy Corp,EQT Corp., Exelon Corp, FedEx Corporation, First Solar Inc, FirstEnergy Corp, Genesee & Wyoming Inc., Gulfport Energy Corp, Hess Corporation, HuskyEnergy Inc, Imperial Oil Ltd, Israel Chemicals Ltd., J.B. Hunt Transport Services Inc., Kansas City Southern, Kinder Morgan Inc., LyondellBasell IndustriesN.V., Magellan Midstream Partners LP, Marathon Oil Corporation, MEG Energy Corp, Midcoast Energy Partners LP, Monsanto Company, Mosaic Company,MPLX LP, Murphy Oil Corporation, Newfield Exploration Co., NextEra Energy Inc, Noble Energy Inc., Norfolk Southern Corp., NRG Energy Inc, OasisPetroleum Inc., Occidental Petroleum, Old Dominion Freight Line Inc, Oneok Inc., ONEOK PARTNERS LP, Parsley Energy Inc, Pioneer Natural ResourcesCo., Plains All American Pipeline LP, Platform Specialty Products Corporation, Potash Corp of Saskatchewan Inc, PPG Industries Inc., Praxair Inc., PublicService Enterprise Group Inc, Range Resources Corp., SemGroup Corp, Sherwin-Williams Co., Southwestern Energy Co, Spectra Energy Partners LP,Suncor Energy Inc, Sunoco Logistics Partners LP, Sunoco LP, SunPower Corp, Tallgrass Energy Partners LP, Targa Resources Corp., TC Pipelines LP, TheDow Chemical Co., Union Pacific Corp., United Parcel Service, Western Gas Equity Partners, L.P., Western Gas Partners LP, Whiting PetroleumCorporation, Williams Companies, Inc, Williams Partners LP, XPO Logistics, Inc..An employee, director or consultant of Morgan Stanley is a director of AES Corp., Marathon Oil Corporation, Norfolk Southern Corp.. This person is not aresearch analyst or a member of a research analyst's household.Morgan Stanley & Co. LLC makes a market in the securities of AES Corp., Agrium Inc., Air Products and Chemicals Inc., Albemarle Corporation, AmericanElectric Power Co, Anadarko Petroleum Corp, Antero Midstream Partners LP, Antero Resources Corp, Apache Corp., ArcBest Corp, Axalta Coating SystemsLtd, Boardwalk Pipeline Partners LP, Buckeye Partners LP, C.H. Robinson Worldwide Inc., Cabot Oil & Gas Corp., California Resources Corp, Calpine Corp.,Canadian National Railway Co., Canadian Natural Resources Ltd, Canadian Pacific Railway Ltd., Celanese Corp., Cenovus Energy Inc, CF Industries,Cheniere Energy Inc., Cheniere Energy Partners L.P., Cimarex Energy Co., Concho Resources Inc., ConocoPhillips, Continental Resources Inc., CSXCorporation, CVR Partners, LP, DCP Midstream LP, Devon Energy Corp, Diamondback Energy Inc, Dominion Resources Inc, E.I. DuPont de Nemours & Co.,Eastman Chemical Co, Echo Global Logistics Inc, Eclipse Resources Corp, Enable Midstream Partners LP, Enbridge Energy Partners LP, Encana Corp.,Energen Corp., Energy Transfer Equity, LP, Energy Transfer Partners LP, EnLink Midstream LLC, EnLink Midstream Partners LP, Entergy Corp, EnterpriseProducts Partners LP, EOG Resources Inc, EP Energy Corp, EQT Corp., EQT Midstream Partners LP, Exelon Corp, Expeditors International of Washington I,FedEx Corporation, First Solar Inc, FirstEnergy Corp, Genesee & Wyoming Inc., Gulfport Energy Corp, Hannon Armstrong, Heartland Express Inc., HessCorporation, Hub Group Inc, Imperial Oil Ltd, J.B. Hunt Transport Services Inc., Kansas City Southern, Kinder Morgan Inc., Knight Transportation Inc.,Landstar System Inc, LyondellBasell Industries N.V., Magellan Midstream Partners LP, Marathon Oil Corporation, Monsanto Company, Mosaic Company,MPLX LP, Murphy Oil Corporation, Newfield Exploration Co., NextEra Energy Inc, Noble Energy Inc., Norfolk Southern Corp., NRG Energy Inc, OasisPetroleum Inc., Occidental Petroleum, Old Dominion Freight Line Inc, Oneok Inc., ONEOK PARTNERS LP, Parsley Energy Inc, Phillips 66 Partners LP,Pioneer Natural Resources Co., Plains All American Pipeline LP, Platform Specialty Products Corporation, Plug Power Inc., Potash Corp of SaskatchewanInc, PPG Industries Inc., Praxair Inc., Public Service Enterprise Group Inc, Range Resources Corp., RPM International Inc., Rsp Permian Inc, Saia, Inc.,SemGroup Corp, Shell Midstream Partners, LP, Sherwin-Williams Co., Southwestern Energy Co, Spectra Energy Partners LP, Suncor Energy Inc, SunocoLogistics Partners LP, Sunoco LP, SunPower Corp, Sunrun Inc, Swift Transportation, Tallgrass Energy Partners LP, Targa Resources Corp., TC Pipelines LP,Tesoro Logistics LP, The Dow Chemical Co., Trinseo S.A., Union Pacific Corp., United Parcel Service, Valspar Corp., Werner Enterprises, Western GasEquity Partners, L.P., Western Gas Partners LP, Whiting Petroleum Corporation, Williams Companies, Inc, Williams Partners LP, XPO Logistics, Inc..
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MThe equity research analysts or strategists principally responsible for the preparation of Morgan Stanley Research have received compensation based uponvarious factors, including quality of research, investor client feedback, stock picking, competitive factors, firm revenues and overall investment bankingrevenues. Equity Research analysts' or strategists' compensation is not linked to investment banking or capital markets transactions performed by MorganStanley or the profitability or revenues of particular trading desks.Morgan Stanley and its affiliates do business that relates to companies/instruments covered in Morgan Stanley Research, including market making, providingliquidity, fund management, commercial banking, extension of credit, investment services and investment banking. Morgan Stanley sells to and buys fromcustomers the securities/instruments of companies covered in Morgan Stanley Research on a principal basis. Morgan Stanley may have a position in the debtof the Company or instruments discussed in this report. Morgan Stanley trades or may trade as principal in the debt securities (or in related derivatives) thatare the subject of the debt research report.Certain disclosures listed above are also for compliance with applicable regulations in non-US jurisdictions.STOCK RATINGSMorgan Stanley uses a relative rating system using terms such as Overweight, Equal-weight, Not-Rated or Underweight (see definitions below). MorganStanley does not assign ratings of Buy, Hold or Sell to the stocks we cover. Overweight, Equal-weight, Not-Rated and Underweight are not the equivalent ofbuy, hold and sell. Investors should carefully read the definitions of all ratings used in Morgan Stanley Research. In addition, since Morgan Stanley Researchcontains more complete information concerning the analyst's views, investors should carefully read Morgan Stanley Research, in its entirety, and not infer thecontents from the rating alone. In any case, ratings (or research) should not be used or relied upon as investment advice. An investor's decision to buy or sell astock should depend on individual circumstances (such as the investor's existing holdings) and other considerations.Global Stock Ratings Distribution(as of February 28, 2017)The Stock Ratings described below apply to Morgan Stanley's Fundamental Equity Research and do not apply to Debt Research produced by the Firm.For disclosure purposes only (in accordance with NASD and NYSE requirements), we include the category headings of Buy, Hold, and Sell alongside ourratings of Overweight, Equal-weight, Not-Rated and Underweight. Morgan Stanley does not assign ratings of Buy, Hold or Sell to the stocks we cover.Overweight, Equal-weight, Not-Rated and Underweight are not the equivalent of buy, hold, and sell but represent recommended relative weightings (seedefinitions below). To satisfy regulatory requirements, we correspond Overweight, our most positive stock rating, with a buy recommendation; we correspondEqual-weight and Not-Rated to hold and Underweight to sell recommendations, respectively.

COVERAGE UNIVERSE INVESTMENT BANKING CLIENTS (IBC) OTHER MATERIALINVESTMENT SERVICES

CLIENTS (MISC)STOCK RATINGCATEGORY

COUNT % OFTOTAL

COUNT % OFTOTAL IBC

% OFRATING

CATEGORY

COUNT % OFTOTAL

OTHERMISC

Overweight/Buy 1148 35% 286 43% 25% 551 36%Equal-weight/Hold 1418 43% 297 45% 21% 699 46%Not-Rated/Hold 61 2% 8 1% 13% 8 1%Underweight/Sell 638 20% 76 11% 12% 269 18%TOTAL 3,265 667 1527

Data include common stock and ADRs currently assigned ratings. Investment Banking Clients are companies from whom Morgan Stanley received investmentbanking compensation in the last 12 months.Analyst Stock RatingsOverweight (O). The stock's total return is expected to exceed the average total return of the analyst's industry (or industry team's) coverage universe, on arisk-adjusted basis, over the next 12-18 months.Equal-weight (E). The stock's total return is expected to be in line with the average total return of the analyst's industry (or industry team's) coverage universe,on a risk-adjusted basis, over the next 12-18 months.Not-Rated (NR). Currently the analyst does not have adequate conviction about the stock's total return relative to the average total return of the analyst'sindustry (or industry team's) coverage universe, on a risk-adjusted basis, over the next 12-18 months.Underweight (U). The stock's total return is expected to be below the average total return of the analyst's industry (or industry team's) coverage universe, on arisk-adjusted basis, over the next 12-18 months.Unless otherwise specified, the time frame for price targets included in Morgan Stanley Research is 12 to 18 months.Analyst Industry ViewsAttractive (A): The analyst expects the performance of his or her industry coverage universe over the next 12-18 months to be attractive vs. the relevant broadmarket benchmark, as indicated below.In-Line (I): The analyst expects the performance of his or her industry coverage universe over the next 12-18 months to be in line with the relevant broad marketbenchmark, as indicated below.Cautious (C): The analyst views the performance of his or her industry coverage universe over the next 12-18 months with caution vs. the relevant broad marketbenchmark, as indicated below.Benchmarks for each region are as follows: North America - S&P 500; Latin America - relevant MSCI country index or MSCI Latin America Index; Europe -MSCI Europe; Japan - TOPIX; Asia - relevant MSCI country index or MSCI sub-regional index or MSCI AC Asia Pacific ex Japan Index.Important Disclosures for Morgan Stanley Smith Barney LLC CustomersImportant disclosures regarding the relationship between the companies that are the subject of Morgan Stanley Research and Morgan Stanley Smith BarneyLLC or Morgan Stanley or any of their affiliates, are available on the Morgan Stanley Wealth Management disclosure website atwww.morganstanley.com/online/researchdisclosures. For Morgan Stanley specific disclosures, you may refer towww.morganstanley.com/researchdisclosures.

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Each Morgan Stanley Equity Research report is reviewed and approved on behalf of Morgan Stanley Smith Barney LLC. This review and approval is conductedby the same person who reviews the Equity Research report on behalf of Morgan Stanley. This could create a conflict of interest.Other Important DisclosuresMorgan Stanley & Co. International PLC and its affiliates have a significant financial interest in the debt securities of AES Corp., American Electric Power Co,Anadarko Petroleum Corp, Antero Resources Corp, Apache Corp., Buckeye Partners LP, C.H. Robinson Worldwide Inc., California Resources Corp, CalpineCorp., Canadian National Railway Co., Canadian Natural Resources Ltd, Cenovus Energy Inc, Cheniere Energy Inc., Cheniere Energy Partners L.P., CobaltInternational Energy Inc, Concho Resources Inc., Cone Midstream Partners LP, Continental Resources Inc., CSX Corporation, Devon Energy Corp, DominionResources Inc, Dynegy Inc., E.I. DuPont de Nemours & Co., Eastman Chemical Co, Eclipse Resources Corp, Enable Midstream Partners LP, EnbridgeEnergy Partners LP, Encana Corp., Energen Corp., Energy Transfer Equity, LP, Energy Transfer Partners LP, EnLink Midstream LLC, EnLink MidstreamPartners LP, Entergy Corp, EOG Resources Inc, EQT Midstream Partners LP, Exelon Corp, FedEx Corporation, First Solar Inc, FirstEnergy Corp, Genesee &Wyoming Inc., Gulfport Energy Corp, Hess Corporation, Husky Energy Inc, Kansas City Southern, Kinder Morgan Inc., LyondellBasell Industries N.V.,Magellan Midstream Partners LP, Marathon Oil Corporation, MEG Energy Corp, Midcoast Energy Partners LP, Monsanto Company, Mosaic Company, MPLXLP, Murphy Oil Corporation, Newfield Exploration Co., NextEra Energy Inc, Noble Energy Inc., Norfolk Southern Corp., NRG Energy Inc, Oasis Petroleum Inc.,Occidental Petroleum, Oneok Inc., ONEOK PARTNERS LP, Phillips 66 Partners LP, Pioneer Natural Resources Co., Plains All American Pipeline LP,Platform Specialty Products Corporation, Potash Corp of Saskatchewan Inc, PPG Industries Inc., Praxair Inc., Public Service Enterprise Group Inc, RangeResources Corp., RPM International Inc., Rsp Permian Inc, SemGroup Corp, Sherwin-Williams Co., Southwestern Energy Co, Spectra Energy Partners LP,Suncor Energy Inc, Sunoco LP, Sunrun Inc, Tallgrass Energy Partners LP, Targa Resources Corp., The Dow Chemical Co., Union Pacific Corp., United ParcelService, Valero Energy Partners LP, Valspar Corp., Western Gas Equity Partners, L.P., Western Gas Partners LP, Whiting Petroleum Corporation, WilliamsCompanies, Inc, Williams Partners LP, XPO Logistics, Inc..Morgan Stanley Research policy is to update research reports as and when the Research Analyst and Research Management deem appropriate, based ondevelopments with the issuer, the sector, or the market that may have a material impact on the research views or opinions stated therein. In addition, certainResearch publications are intended to be updated on a regular periodic basis (weekly/monthly/quarterly/annual) and will ordinarily be updated with thatfrequency, unless the Research Analyst and Research Management determine that a different publication schedule is appropriate based on current conditions.Morgan Stanley is not acting as a municipal advisor and the opinions or views contained herein are not intended to be, and do not constitute, advice within themeaning of Section 975 of the Dodd-Frank Wall Street Reform and Consumer Protection Act.Morgan Stanley produces an equity research product called a "Tactical Idea." Views contained in a "Tactical Idea" on a particular stock may be contrary to therecommendations or views expressed in research on the same stock. This may be the result of differing time horizons, methodologies, market events, or otherfactors. For all research available on a particular stock, please contact your sales representative or go to Matrix at http://www.morganstanley.com/matrix.Morgan Stanley Research is provided to our clients through our proprietary research portal on Matrix and also distributed electronically by Morgan Stanley toclients. Certain, but not all, Morgan Stanley Research products are also made available to clients through third-party vendors or redistributed to clients throughalternate electronic means as a convenience. For access to all available Morgan Stanley Research, please contact your sales representative or go to Matrix athttp://www.morganstanley.com/matrix.Any access and/or use of Morgan Stanley Research is subject to Morgan Stanley's Terms of Use (http://www.morganstanley.com/terms.html). By accessingand/or using Morgan Stanley Research, you are indicating that you have read and agree to be bound by our Terms of Use(http://www.morganstanley.com/terms.html). In addition you consent to Morgan Stanley processing your personal data and using cookies in accordance withour Privacy Policy and our Global Cookies Policy (http://www.morganstanley.com/privacy_pledge.html), including for the purposes of setting your preferencesand to collect readership data so that we can deliver better and more personalized service and products to you. To find out more information about how MorganStanley processes personal data, how we use cookies and how to reject cookies see our Privacy Policy and our Global Cookies Policy(http://www.morganstanley.com/privacy_pledge.html).If you do not agree to our Terms of Use and/or if you do not wish to provide your consent to Morgan Stanley processing your personal data or using cookiesplease do not access our research.Morgan Stanley Research does not provide individually tailored investment advice. Morgan Stanley Research has been prepared without regard to thecircumstances and objectives of those who receive it. Morgan Stanley recommends that investors independently evaluate particular investments andstrategies, and encourages investors to seek the advice of a financial adviser. The appropriateness of an investment or strategy will depend on an investor'scircumstances and objectives. The securities, instruments, or strategies discussed in Morgan Stanley Research may not be suitable for all investors, andcertain investors may not be eligible to purchase or participate in some or all of them. Morgan Stanley Research is not an offer to buy or sell or the solicitationof an offer to buy or sell any security/instrument or to participate in any particular trading strategy. The value of and income from your investments may varybecause of changes in interest rates, foreign exchange rates, default rates, prepayment rates, securities/instruments prices, market indexes, operational orfinancial conditions of companies or other factors. There may be time limitations on the exercise of options or other rights in securities/instrumentstransactions. Past performance is not necessarily a guide to future performance. Estimates of future performance are based on assumptions that may not berealized. If provided, and unless otherwise stated, the closing price on the cover page is that of the primary exchange for the subject company'ssecurities/instruments.The fixed income research analysts, strategists or economists principally responsible for the preparation of Morgan Stanley Research have receivedcompensation based upon various factors, including quality, accuracy and value of research, firm profitability or revenues (which include fixed income tradingand capital markets profitability or revenues), client feedback and competitive factors. Fixed Income Research analysts', strategists' or economists'compensation is not linked to investment banking or capital markets transactions performed by Morgan Stanley or the profitability or revenues of particulartrading desks.The "Important US Regulatory Disclosures on Subject Companies" section in Morgan Stanley Research lists all companies mentioned where Morgan Stanleyowns 1% or more of a class of common equity securities of the companies. For all other companies mentioned in Morgan Stanley Research, Morgan Stanleymay have an investment of less than 1% in securities/instruments or derivatives of securities/instruments of companies and may trade them in ways differentfrom those discussed in Morgan Stanley Research. 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INDUSTRY COVERAGE: Diversified Utilities / IPPs

COMPANY (TICKER) RATING (AS OF) PRICE* (03/24/2017)

Devin McDermottDynegy Inc. (DYN.N) O (04/20/2015) $7.33Public Service Enterprise Group Inc (PEG.N) E (01/09/2017) $45.15

Stephen C ByrdAES Corp. (AES.N) E (05/22/2014) $11.23American Electric Power Co (AEP.N) E (08/04/2014) $67.79Calpine Corp. (CPN.N) E (02/05/2017) $10.80Dominion Resources Inc (D.N) E (08/08/2016) $78.26Entergy Corp (ETR.N) U (10/27/2016) $76.81Exelon Corp (EXC.N) E (03/28/2017) $36.12FirstEnergy Corp (FE.N) O (08/08/2016) $31.34NextEra Energy Inc (NEE.N) O (07/22/2014) $132.80NRG Energy Inc (NRG.N) O (01/17/2013) $18.16

Stock Ratings are subject to change. Please see latest research for each company.* Historical prices are not split adjusted.

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INDUSTRY COVERAGE: Clean Tech

Stephen C ByrdFirst Solar Inc (FSLR.O) E (02/07/2011) $28.31Hannon Armstrong (HASI.N) E (02/03/2016) $19.39Plug Power Inc. (PLUG.O) E (04/09/2015) $1.36SunPower Corp (SPWR.O) E (08/12/2016) $6.07Sunrun Inc (RUN.O) O (09/08/2015) $4.91TPI Composites Inc. (TPIC.O) O (08/16/2016) $16.46


INDUSTRY COVERAGE: Mid-Cap Exploration & Production


Drew Venker, CFAAntero Resources Corp (AR.N) E (03/24/2016) $22.49Cabot Oil & Gas Corp. (COG.N) E (06/24/2014) $23.18Cimarex Energy Co. (XEC.N) O (09/09/2013) $116.65Concho Resources Inc. (CXO.N) O (06/13/2016) $125.18Continental Resources Inc. (CLR.N) O (07/17/2013) $42.51Diamondback Energy Inc (FANG.O) O (03/26/2015) $99.73Eclipse Resources Corp (ECR.N) E (12/03/2014) $2.37Energen Corp. (EGN.N) E (03/26/2015) $51.51EP Energy Corp (EPE.N) U (02/19/2016) $4.37EQT Corp. (EQT.N) E (03/02/2016) $57.30Gulfport Energy Corp (GPOR.O) E (09/08/2014) $16.23Oasis Petroleum Inc. (OAS.N) E (12/10/2012) $12.37Parsley Energy Inc (PE.N) O (07/21/2016) $30.47Range Resources Corp. (RRC.N) E (09/20/2016) $27.68Rsp Permian Inc (RSPP.N) O (12/05/2016) $38.65Southwestern Energy Co (SWN.N) U (12/10/2012) $7.56Whiting Petroleum Corporation (WLL.N) E (06/23/2016) $8.22


INDUSTRY COVERAGE: Chemicals


Neel Kumar, CFAPlatform Specialty Products Corporation (PAH.N) E (01/30/2017) $12.55Versum Materials, Inc. (VSM.N) E (10/03/2016) $29.87

Vincent AndrewsAgrium Inc. (AGU.N) ++ $94.80Air Products and Chemicals Inc. (APD.N) E (04/26/2012) $134.94Albemarle Corporation (ALB.N) E (09/18/2012) $104.45Axalta Coating Systems Ltd (AXTA.N) E (12/09/2015) $30.86Celanese Corp. (CE.N) E (10/08/2012) $89.47CF Industries (CF.N) E (05/25/2016) $29.18CVR Partners, LP (UAN.N) $4.67E.I. DuPont de Nemours & Co. (DD.N) ++ $79.60Eastman Chemical Co (EMN.N) E (11/10/2014) $77.18Intrepid Potash (IPI.N) U (10/03/2013) $1.64Israel Chemicals Ltd. (ICL.N) E (11/03/2014) $4.35LyondellBasell Industries N.V. (LYB.N) O (11/15/2011) $87.56Monsanto Company (MON.N) ++ $113.67Mosaic Company (MOS.N) E (03/16/2016) $28.75Potash Corp of Saskatchewan Inc (POT.N) ++ $17.02PPG Industries Inc. (PPG.N) E (02/03/2015) $103.79Praxair Inc. (PX.N) ++ $116.41RPM International Inc. (RPM.N) O (03/19/2014) $54.03Sherwin-Williams Co. (SHW.N) O (03/19/2014) $309.45The Dow Chemical Co. (DOW.N) ++ $63.08Trinseo S.A. (TSE.N) E (07/22/2014) $64.90Valspar Corp. (VAL.N) U (03/19/2014) $111.00

64

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MStock Ratings are subject to change. Please see latest research for each company.* Historical prices are not split adjusted.

INDUSTRY COVERAGE: Coal

COMPANY (TICKER) RATING (AS OF) PRICE* (//)


INDUSTRY COVERAGE: Midstream Energy MLPs


Fotis GiannakoulisCheniere Energy Partners L.P. (CQP.A) O (03/01/2016) $31.90

Tom AbramsAntero Midstream Partners LP (AM.N) E (04/12/2016) $33.54Boardwalk Pipeline Partners LP (BWP.N) E (06/09/2014) $17.50Buckeye Partners LP (BPL.N) O (02/25/2016) $66.89Cone Midstream Partners LP (CNNX.N) E (04/12/2016) $21.00DCP Midstream LP (DCP.N) U (01/15/2015) $37.32Dominion Midstream Partners LP (DM.N) E (08/18/2016) $31.45Enable Midstream Partners LP (ENBL.N) U (02/25/2016) $16.44Enbridge Energy Partners LP (EEP.N) O (03/23/2017) $18.13Enbridge Energy Partners LP (EEQ.N) O (03/23/2017) $17.89Energy Transfer Equity, LP (ETE.N) O (08/15/2016) $18.90Energy Transfer Partners LP (ETP.N) E (08/15/2016) $35.83EnLink Midstream LLC (ENLC.N) E (04/12/2016) $18.35EnLink Midstream Partners LP (ENLK.N) O (09/02/2016) $17.44Enterprise Products Partners LP (EPD.N) E (08/18/2016) $27.07EQT GP Holdings LP (EQGP.N) O (02/14/2017) $26.65EQT Midstream Partners LP (EQM.N) O (02/14/2017) $76.41Magellan Midstream Partners LP (MMP.N) U (08/18/2016) $76.46Midcoast Energy Partners LP (MEP.N) $7.95MPLX LP (MPLX.N) E (06/09/2014) $35.41ONEOK PARTNERS LP (OKS.N) ++ $51.79Phillips 66 Partners LP (PSXP.N) O (02/25/2016) $50.23Plains All American Pipeline LP (PAA.N) O (10/04/2016) $31.30SemGroup Corp (SEMG.N) E (04/12/2016) $33.10Shell Midstream Partners, LP (SHLX.N) E (06/16/2016) $31.47Spectra Energy Partners LP (SEP.N) U (03/23/2017) $42.28Sunoco Logistics Partners LP (SXL.N) E (08/15/2016) $24.01Sunoco LP (SUN.N) E (08/15/2016) $24.37Tallgrass Energy GP LP (TEGP.N) E (04/12/2016) $28.04Tallgrass Energy Partners LP (TEP.N) E (04/12/2016) $52.27TC Pipelines LP (TCP.N) U (04/12/2016) $59.44Tesoro Logistics LP (TLLP.N) O (01/06/2017) $52.85Valero Energy Partners LP (VLP.N) E (01/06/2017) $47.32Western Gas Equity Partners, L.P. (WGP.N) E (02/25/2016) $44.77Western Gas Partners LP (WES.N) E (02/25/2016) $59.45Williams Partners LP (WPZ.N) O (08/02/2016) $40.08


HIGHLY RESTRICTED

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© 2017

HIGHLY RESTRICTED
INDUSTRY COVERAGE: Freight Transportation

Ravi ShankerArcBest Corp (ARCB.O) E (10/06/2011) $25.30C.H. Robinson Worldwide Inc. (CHRW.O) U (06/09/2013) $77.47Canadian National Railway Co. (CNR.TO) O (02/23/2016) C$96.75Canadian Pacific Railway Ltd. (CP.TO) O (06/03/2016) C$194.65CSX Corporation (CSX.O) E (01/19/2017) $46.32Echo Global Logistics Inc (ECHO.O) O (07/16/2012) $20.50Expeditors International of Washington I (EXPD.O) E (02/25/2015) $55.82FedEx Corporation (FDX.N) E (06/20/2013) $188.12Genesee & Wyoming Inc. (GWR.N) E (02/23/2016) $65.17Heartland Express Inc. (HTLD.O) U (05/06/2011) $19.92Hub Group Inc (HUBG.O) E (07/16/2012) $45.75J.B. Hunt Transport Services Inc. (JBHT.O) E (05/06/2011) $90.27Kansas City Southern (KSU.N) E (02/23/2016) $82.64Knight Transportation Inc. (KNX.N) O (02/23/2016) $31.05Landstar System Inc (LSTR.O) U (02/23/2016) $83.60Norfolk Southern Corp. (NSC.N) U (06/03/2016) $110.66Old Dominion Freight Line Inc (ODFL.O) O (10/06/2011) $84.73Saia, Inc. (SAIA.O) U (02/23/2016) $42.70Swift Transportation (SWFT.N) O (02/23/2016) $19.74Union Pacific Corp. (UNP.N) O (06/03/2016) $103.96United Parcel Service (UPS.N) U (02/23/2016) $105.05Werner Enterprises (WERN.O) O (02/23/2016) $26.05XPO Logistics, Inc. (XPO.N) O (11/16/2015) $46.14


INDUSTRY COVERAGE: Large-Cap Exploration & Production


Evan CalioAnadarko Petroleum Corp (APC.N) O (10/19/2011) $60.34Apache Corp. (APA.N) E (11/20/2012) $50.24California Resources Corp (CRC.N) E (11/22/2016) $12.97Cobalt International Energy Inc (CIE.N) NR (08/04/2016) $0.41ConocoPhillips (COP.N) E (04/11/2014) $44.10Devon Energy Corp (DVN.N) O (04/18/2016) $38.80EOG Resources Inc (EOG.N) E (12/16/2014) $94.86Hess Corporation (HES.N) E (01/12/2016) $46.10Marathon Oil Corporation (MRO.N) O (06/20/2016) $14.61Murphy Oil Corporation (MUR.N) U (07/13/2015) $25.76Newfield Exploration Co. (NFX.N) E (10/31/2016) $33.50Noble Energy Inc. (NBL.N) O (09/20/2015) $32.82Occidental Petroleum (OXY.N) E (06/13/2016) $62.83Pioneer Natural Resources Co. (PXD.N) O (07/13/2015) $180.91


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