Morgan Stanley’s analysts - · PDF fileM O R G A N S T A N L E Y R E S E A R C H ....

M O R G A N S T A N L E Y R E S E A R C H Global Morgan Stanley & Co. LLC Adam Longson, CFA, CPA [email protected] +1 212 761 4061 Stefan Revielle [email protected] +1 212 761 6005 Elizabeth Volynsky [email protected] +1 212 761 7201

January Energy Marketing Guide

January 2015

ENERGY COMMODITY STRATEGY

Cover photo: West Azeri oil platform; photo credit: BP p.l.c. For other important disclosures, refer to the Disclosure Section, located at the end of this report.

M O R G A N S T A N L E Y R E S E A R C H

2

Energy Outlook January 2015

Sources: IEA, JODI, Rystad Energy, Morgan Stanley Commodity Research

Supply Will Outpace Demand, But More So in 1H15 (global crude supply and demand, mmb/d)

With OPEC on the Sidelines, Plenty of Headwinds for 2015 It likely gets worse before it gets better: Bearish 1H15, but recovery could come as early as 2H15. 2015 and 2016 have always represented the most challenging years for this cycle from an S&D perspective. However, without any accommodation from OPEC, the risk to prices is significantly elevated.

OPEC or some other intervention is eventually required, most of which would come through lower prices. Although estimates of the oversupply are overstated, we see a large imbalance developing by the spring without some intervention. While we see forces to balance the market without OPEC, perhaps as early as 2H15, these will not come into play without low prices remaining in place over the coming months.

Other headwinds add to the price risk and overcorrections are possible: These include expected USD strength, some inventory overhang from this summer, and extremely bearish sentiment. Supply upside vs. our estimates could also come from Iraq/Kurdistan, Libya or Iran, if there was a change in circumstances. With little short term intrinsic value in crude oil markets, momentum will continue to be a driving force for prices.

But not all hope is lost – we see a path for recovery potentially as early as 2H15. A number of upside risks are underappreciated, and prices are path dependent. The lower prices fall in the interim, the more reaction we will see in the physical market – and into later years. Lower prices will curtail investment, increase the risk of OPEC intervention or an outage, or even shut in wells. Based on our forecasts, activity should slow sharply, and if intervention is large and swift, price recovery in 2H15 could be swift as well.

By 2020, Material Supply Is Needed Which Requires Higher Prices (mmb/d)


76.076.577.077.578.078.579.079.580.080.581.0

Global Crude Supply Global Crude Demand

MS estimates

0

5

10

15

20

25

30

2014-2020e GlobalCrude Demand

2014-2020e Non-OPECCrude Supply

2015-2020e CumulativeGross Additions


3


Sources: Rystad Energy, Company reports, Morgan Stanley Commodity Research

Major Capacity Additions Will Continue in 2015 (largest capacity additions ex-US shale in 2015, mmb/d)

Supply Is Likely To Continue To Come Online Despite Low Prices Global crude supply will continue to ramp in the near-term. The largest of these projects, ex-US shale, are located in Brazil, Iraq, West Africa, Canada, and the US Gulf of Mexico. Many of these large additions are complex offshore projects with long lead times and sunk capital.

Even in the US, production momentum can continue for some time. Some wells have already been drilled and simply need to be tied in, while hedges can keep production going from a number of large producers. In fact, the full impact of greater pad drilling in 2014 has not been felt by the market.

Growing supply and exports have offset lower production from Libya. The market has been able to look through any lower output from Libya as too small to balance the market. At the same time, rising exports from Russia, Iraq (namely KRG), and even the WAF and the North Sea have offset any outages.

One of the few positives is that US producers may be delaying completions. Some producers have looked to avoid these costs and maximize NPV on short life cycle wells. At the same time, these efforts may simply delay production and may be targeted at securing lower service costs.

Many Regions Will Continue to See Growth in 2015, Even the US (YoY growth, kb/d)

Sources: IEA, Rystad Energy, Morgan Stanley Commodity Research

Field Name CountryDepth

2015 Gross Additions

West Qurna 2 Iraq Land 245

Roncador III and IV Brazil Ultra deepwater (1500+ meter) 177

Kambesah Mexico Shelf (to 125 meter) 125

Parque das Baleia Brazil Deep water (125-1500 meter) 116

Block 17 CLOV Angola Deep water (125-1500 meter) 105

Ku-Maloob-Zaap Project Mexico Shelf (to 125 meter) 91

Tawke Iraq Land 88

Sapinhoa Brazil Ultra deepwater (1500+ meter) 82

Western Hub (Block 15/06) Angola Deep water (125-1500 meter) 79

Lucius (KC875) USA Ultra deepwater (1500+ meter) 70

Jack/St. Malo USA Ultra deepwater (1500+ meter) 62

Kearl Canada bitumen Land 62

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Aug-

15

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GoM Canada Brazil Iraq


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While Demand Should Weaken Seasonally Seasonal refinery maintenance is likely to ramp up. US turnarounds will pick up substantially in February. However, global refinery maintenance tends to peak in Apr/May, particularly Europe and Asia.

Refinery margins may struggle to stay so healthy. Refiners have benefitted from a period of strong runs and margins, partly helped by lower crude prices and a realignment of crude diffs. However, with global competition rising, such an environment should prove unsustainable. In fact, refinery excesses were responsible for the initial sell off in crude in later summer 2014.

Inventories are set to build well above normal, with the peak dislocation occurring in 2Q15. With crude supply growing, OPEC unwilling to intervene, and demand falling seasonally, a dislocation is coming. Although the market may be overestimating the magnitude, stocks will build above seasonal norms.

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

2015 2014 2013 2012 2011 5Y Avg

(2,500)

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(500)

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500

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15

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Difference vs. 5Y Median Implied Global Crude Stock ∆5Y Median Implied Stock ∆

Peak distress likely Apr-Jun

But avg draws possible by year

end

Seasonal Crude Demand Will Play An Important Role in Quarterly Balances (global crude demand, mmb/d)


Implied Stock Draws Fall Well Below Norms in 2Q15, But Recover in 2H15 (implied global crude stock change, kb/d)

Sources: IEA, JODI, Morgan Stanley Commodity Research estimates


5


Curve Structure Reinforces Inventory Overhang Deep contango, floating storage reinforce downside risk for oil over the coming months. Brent and Dubai have moved into a steeper contango (both sit at $1+/bbl of contango) as fears grow about the 2Q15 S&D and limited storage options. Carry trades are now open for onshore and offshore storage, which should drive inventory builds..

Floating storage already starting. Increased barrels are moving to South Africa for storage, just as we saw during late summer 2014. However, last week, Dynacom Tankers said that traders are looking for at least 10 VLCCs for floating storage (~20 mmb), with a handful of vessels already booked for offshore storage. If larger quantities of floating storage are required over the coming months, the Brent contango is likely to steepen to support rising VLCC utilization and freight rates.

Inventory overhangs can limit price recovery. While more important for curve structure, a large inventory build would be problematic, as even when fundamentals turn, inventory overhangs typically need to be worked off before prices see a sustainable rally (e.g. 2010).

Prices Were Slow to Respond To Global Stock Draw in 2010 Given Inventory Overhang (left axis: IEA stock Δ & misc to balance, kb/d; right axis: Brent price inverted, $/bbl)

Source: Bloomberg, Platts, Morgan Stanley Commodity Research

Deep Contango = Floating Storage Attractive Again (prompt month structure, $/bbl)

Source: IEA crude/liquids balance, Bloomberg, Morgan Stanley Commodity Research


6


In An Extreme Example, Even Shut-In Economics Do Not Provide A Short Term Floor The oil price is somewhat meaningless in the short run except at extreme levels. A $10-$20/bbl move in oil price does not have much immediate impact in oil markets. There is little immediate response from physical markets that can push back. The only immediate critical levels are extreme highs – where demand is destroyed – or extreme lows where existing production struggles to stay online. But even here, there is a delayed response.

However, crude prices can fall below shut-in economics in the short run. Producers are extremely reluctant to shut in, even when below cash costs. 1) Many costs are fixed and cannot easily be shed (e.g. labor, equipment, leases, etc). 2) Cash costs can fall: lower demand and sustaining capex can help. 3) Restart costs can be high for such a temporary measure. 4) Potential field damage if production is disrupted.

At a minimum, producers will be slow to respond to price signals. Decisions to shut in production are not taken lightly and could require board approval. Moreover, many producers do not believe these extreme low prices will be sustained, which limits action.

Rhetoric surrounding OPEC continues to suggest that it will not act as a backstop for prices. Saudi Arabia and other GCC countries continue to point out that lower oil prices are not harmful and that the market (via non-OPEC) needs to adjust. Repeated calls for emergency OPEC meetings (mainly by Venezuela) have been ignored.

Cash Costs Can Slide Lower In Lower Oil Price Environment

Sources: Rystad Energy, Morgan Stanley Commodity Research

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0

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300

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Jan-

08

Mar

-08

May

-08

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8

Sep-

08

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-08

Jan-

09

Mar

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9

Sep-

09

Nov

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Jan-

10

Mar

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Jul-1

0

Sep-

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-10

US L48 ex. GoM Canada Russia

Low Prices Did Not Trigger Any Notable Shut Ins During 2009 (YoY ∆ in non-OPEC crude supply, kb/d)

Sources: IEA, Morgan Stanley Commodity Research

(y axis: Operating costs with and without royalty effects, $/bbl; x axis: Cumulative global liquids production, mmb/d)

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$10

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0 10 20 30 40 50 60 70 80 90Cash costs without royalties (Dec 2014)Cash Costs with Royalties (Dec 2014)With royalties (Jan 2015)

Canada OilsandsVenezuela

UKCanada ex Oilsands

UAEChina

Saudi Arabia

Iraq

Mexico

ChinaUS

RussiaIran


7


(US crude oil production growth YoY, kb/d)

Sources: IEA, Rystad Energy, Morgan Stanley Commodity Research

We Now See Much Lower Non-OPEC Crude Supply Growth in 2015 (crude oil only production growth in 2014 vs. 2015e, kb/d)

Without OPEC, Low Prices Are Needed to Slow Production Supply Growth is Likely to Slow and Could Come In Below Our Estimates We expect to see a material slow down in capital investment in the coming months if current prices hold). US E&Ps have already announced cuts of 20-50%, with another 20-40% cut being proposed for spring, which should impact production in 2H15. North America has plenty of momentum into 1H15, and efficiency gains and more focused capital spending provide some offset (e.g., focus on the core). However, a rapid deceleration is possible in 2H15 that will significantly slow production in 2016. While US production growth and capex could return rather quickly, it’s unlikely to occur without much higher prices.

Under our base case, we see US crude production (incl. GoM) slowing to ~600 kb/d in 2015 and decline 100-200 kb/d in 2016. Sustained lower prices would cause a greater pullback.

International projects will lose funding as well, but the impact will be delayed. While we see a number of higher cost projects outside the US, many of the projects of this scope that are close to completion will continue to come online. The delayed impact of cutting from this project pool will likely be felt in later years.

Sources: IEA, HPDI, Morgan Stanley Commodity Research

-500 0 500 1000 1500

Former USSR excluding EstoniaNon-OPEC Africa

MexicoNon-OPEC Middle East

OECD Asia OceaniaNon-OECD Europe

OtherAsia ex China

ChinaCanada

OECD EuropeNon-OPEC Latin America

United StatesTotal Non-OPEC

2014 growth

2015e growth

GoM Has Been A Growing Source of Additions Along with Tight Oil

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Unconventional Alaska ConventionalGoM Total US production

MS estimates


8


(1,000)

(500)

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500

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Jan-

09Fe

b-09

Mar

-09

Apr-0

9M

ay-0

9Ju

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9Au

g-09

Sep-

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ec-0

9Ja

n-10

Feb-

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ar-1

0Ap

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l-10

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OECD Americas Other OECDFSU Asia Non-OPEC Latin America Other Non-OPECTotal Non-OPEC

GoM outage in 2008

However, Production Continued To Grow As Major Projects Came Online (YoY crude supply ∆ by region, mmb/d)

Sources: Rystad Energy, Bloomberg, Morgan Stanley Commodity Research

Capex In Major Non-OPEC Producing Regions Declined Along With Price in 2009 (left axis: YoY Capex ∆ by region in 2009, $ billions; right axis: YoY ∆ in Brent price, $/bbl

2009 Offers A Warning: Capex Fell Dramatically, But Production Still Grew Prices fell by ~75% in late 2008, leading to major capex cuts in 2009. According to Rystad data, global capex was cut by $36 billion, over two-thirds of which took place in North America (US+Canada).

Despite the cuts, US production grew YoY as several large Gulf of Mexico projects started up and/or continued to add capacity in 2009. These included Thurnderhorse (250 kb/d), Tahiti (125 kb/d), and Shenzi (100 kb/d).

Even in Canada where capex fell by a similar amount, the 110 kb/d Horizon oil sands and upgrading project still came online and additional phases of Foster Creek (120 kb/d) came on.

And finally in Russia, where capex declined by ~$8 billion, production also increased YoY, because projects, like Vankor (450 kb/d) and Uvat (195 kb/d) came online.

Given the complex and capital-intensive nature of the projects that are expected to add production in 2015, we are skeptical of a quick supply response, especially ex-US shale.

Sources: IEA, Morgan Stanley Commodity Research estimates

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F

US Canada RussiaMiddle East South America OtherYoY Price


9


$31 $42

$51 $52

$61 $61 $62 $64 $65 $66 $68

$75 $75 $78 $81

$87 $87

$92 $98

$0 $50 $100 $150

XEC - Cana WoodfordXEC - Delaware Lower Wolfcamp

WLL - Bakken Dunn Co. (KOG)WLL - Bakken (Sanish)

CLR - Core BakkenHK - Bakken

CXO - Bone SpringWLL - Niobrara (NE Extension)

EPE - Eagle FordWLL - Bakken (West)

AverageBCEI - Niobrara (Wattenberg)

CXO - Midland WolfcampCLR - Avg. Bakken

HK - E. Tx Eagle FordBBG - Niobrara (Wattenberg)

BBG - UintaOAS - Bakken

EPE - Southern Midland Wolfcamp

US Unconventional Production Set To Slow Through 2015 With Lower Prices (US YoY production growth for select plays, kb/d)

Based on company historical realizations Sources: Morgan Stanley Equity Research

US Shale Production On The Margin Is At Risk, Esp Small/Mid-Caps (WTI Breakeven assuming 20% pre-tax IRR, $/bbl)

US Production From Shale Is At Serious Risk Analyzing shale economics is not so simple. US shale is not homogenous, even within the same company or play. Acreage and costs vary wildly, as do infrastructure access and sunk costs. We see producers with viable acreage as low as $30/bbl WTI and as high as $100/bbl. Regardless, lower prices should limit cash flow and spending, while any freeze in the high yield market could quickly close access to capital for producers.

Fringe shale production requires $80/bbl WTI. Analysis by our E&P team suggests that numerous companies’ non-core areas are uneconomic assuming a 20% hurdle rate. Production could be cut in these areas as producers move to most-productive acres and those that require lower transport costs (e.g., Texas). The Bakken is particularly at risk given many producers’ lack of transport infrastructure and high costs of rail.

Slowing production will come on a lagged basis. Much of early 2015 production is already underway and will be hard to curtail at this point. Momentum and improving capital efficiency should keep US growth elevated in early 2015 despite lower prices. Hedges, incentives and other obligations can also support activity beyond what economics would suggest. But at our base case, we should see a rapid reduction in activity into 2H15. According to Drew Venker, at $65/bbl WTI, oil-focused E&Ps could shrink 7% in 2016, which seems untenable.

US unconventional production is most at risk now, but will be the first to return. US shale is not the high cost producer, but given its short lead time, it will be the first to slow in a lower price environment. However, when prices rebound, US shale producers will be able to respond in 3-6 months.

Source: HPDI, Morgan Stanley Commodity Research

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Bakken Permian Eagle Ford Niobrara Total

MS estimates


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Oct-90 Sep-00 Jul-08 Jun-14

US Rig Count Set to Fall Sharply on and Capex Cuts US rig counts tend to follow pricing, but on a lag. In previous oil price cycles, rig counts did not peak until 4-6 months after the peak in oil prices. Similarly, the peak to trough in US oil rig count was around 8 months, but larger cycles can be much longer.

US rigs are already 1-2 months into their descent. Since peaking at just over 1600 in Oct 204, the US oil rig count has fallen sharply, particularly since 2H Dec.

However, the total rig count can be deceptive when it comes to the actual impact on production. Producers will remove rigs with the lowest productivity first (e.g., vertical and directional rigs) and move production to the core areas. Producers could also run their rigs more efficiently, all of which can mute the impact of a lower US rig count.

Rig Count Decline Can Be A Quick And Prolonged Response (y-axis: number of US rigs relative to peak price; x-axis: number of months before/after peak price)

Cycle Start Date StartTough Date Trough % ∆ Months

Peak Date

Peak Count

Trough Date

Trough Count % ∆ Months

Peak Delay

Trough Delay

1986 Nov-85 $29.82 Jul-86 $9.56 -68% 8 1988 Jul-87 $19.83 Oct-88 $12.28 -38% 15 Dec-87 746 Feb-89 392 -47% 14 5 4 1991 Oct-90 $36.09 Jun-91 $18.08 -50% 8 Dec-90 644 Oct-91 433 -33% 10 2 4 1994 Apr-93 $18.63 Feb-94 $13.75 -26% 10 Nov-93 453 Apr-94 315 -30% 5 7 2 1999 Oct-97 $20.05 Sep-99 $9.80 -51% 23 Aug-97 409 Aug-99 111 -73% 24 (2) (1) 2001 Nov-00 $32.52 Dec-01 $18.60 -43% 13 Mar-01 248 Sep-02 122 -51% 18 4 9 2007 Aug-06 $73.61 Jan-07 $54.30 -26% 5 Aug-06 316 Feb-07 266 -16% 6 - 1 2008 Jul-08 $133.90 Dec-08 $41.58 -69% 5 Nov-08 426 May-09 187 -56% 6 4 5 2012 Mar-12 $124.93 Jun-12 $95.59 -23% 3 Aug-12 1,423 Jan-13 1,318 -7% 5 5 7 2015 Jul-14 $106.98 Jan-15 $49.83 -53% 6 Oct-14 1,593 MEDIAN -46% 8 -40% 8 4 4

IMF Brent Spot Price US Oil Rig Count vs. Prices

Sources: Baker Hughes, Morgan Stanley Commodity Research estimates

Drops In Rig Counts Can Be Severe (US oil rig count cycles vs. pricing)


11


Mix Effects Can Help Mitigate The Decline In the Rig Count

The production impact is

smaller than the rig impact

Sources: HPDI, Baker Hughes, Morgan Stanley Commodity Research

Not All Rigs Are Created Equal (US oil rig count by type)

Overall rig counts mask the large variance in performance. When looking at how rigs are deployed, we see significant differences in the impact of each rig. Lower performing plays such as the MS Lime and Niobrara will likely lose rigs first, as will the conventional Permian. However, these rigs add relatively little to US production growth.

The US still has a large number of inefficient vertical and directional rigs. While these wells tend to be cheaper, the average IP rate is just a fraction of new horizontal wells.

High-grading (i.e. moving to the core) and efficiencies gains can further reinforce production. Losing low quality rigs among plays offers a double-digit uplift in weighted average IP. However, producers can pick up efficiencies within plays as well that can further limit the impact of lost rigs.

12/12/2014Rigs by Play IP Count IP Count IP Count IP Count

Bakken 829 172 347 3 347 12 790 187Permian 576 343 72 185 118 12 393 540

Eagle Ford 682 184 215 1 78 3 670 188Niobrara 444 40 47 1 152 1 428 42

Mississippian Lime 446 69 36 3 36 0 429 72Other 300 297 50 110 50 110 194 517Total 546 1105 67 303 83 138 411 1546

MS Dec-15 EstimateRigs by Play IP Count IP Count IP Count IP Count

Bakken 829 87 347 1 347 2 812 90Permian 576 207 72 26 118 2 516 235

Eagle Ford 682 126 215 1 78 1 673 128Niobrara 444 7 47 1 152 1 368 9

Mississippian Lime 446 17 36 1 36 1 403 19Other 300 150 50 48 50 48 202 246Total 560 594 63 78 65 55 470 727

ChangeRigs by Play IP Count IP Count IP Count IP Count

Bakken 0 -85 0 -2 0 -10 23 -97Permian 0 -136 0 -159 0 -10 123 -305

Eagle Ford 0 -58 0 0 0 -2 4 -60Niobrara 0 -33 0 0 0 0 -60 -33

Mississippian Lime 0 -52 0 -2 0 1 -26 -53Other 0 -147 0 -62 0 -62 9 -271Total 15 -511 -4 -225 -18 -83 59 -819

% Change 3% -46% -6% -74% -21% -60% 14% -53%

Horizontal Vertical Directional Total




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Bakken Permian - Midland Permian- DE Eagle Ford

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Bakken Eagle Ford Permian -Midland

Permian -Deleware

Niobrara MississippiLime

Middle 80% range Average Top 25%

IPs Have Been Rising Over Time (IP rates in major US shale plays)

Sources: HPDI, Morgan Stanley Commodity Research

There Is A Wide Range of IP Rates In the Shale Plays (Range of oil IPs from horizontal wells producing in 2014 in various plays)

High-grading The US Drilling Portfolio Offers More Offsets

Sources: HPDI, Morgan Stanley Commodity Research Note: Wells below 300 kb/d filtered out as assumed to be mischaracterized wells

Producers are moving drilling activity to their core and best performing acreage. This is one effort producers are using to further cut capex and yet keep production growth fairly resilient.

We see significant variability within and across plays. We see oil IPs from as low as 100-300 b/d along a number of high quality wells well over 1000 b/d. As a result, a number of high performing wells and rigs contribute an outsized share to US production growth. Focusing on these best-in-class wells may allow producers to lift capital efficiency once again without sacrificing too much production growth.

Efficiency gains can also be had. Oil IPs have been rising slowly over the past several years as producers test new techniques for drilling and completion. Pad drilling is still a rising phenomenon within some plays (e.g. the Permian). We see more room for gains on completion techniques, although spending on R&D is being cut with low prices.


13


0%10%20%30%40%50%60%70%80%90%

100%Ba

kken

Eagl

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ian:

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ian:

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<300 300-499 500-799 800-999 >=1000

0%10%20%30%40%50%60%70%80%90%

100%

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<300 300-499 500-799 800-999 >=1000

Less Room For High-Grading in Horizontal (% of horizontal oil wells drilled in 2014 by oil IP by play)

Sources: HPDI, Morgan Stanley Commodity Research

Sub-300 Oil IP Wells Still Prevalent (% of oil wells drilled in 2014 by oil IP by play)

Plenty of Low Quality Wells Were Drilled in 2014

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<300 300-499 500-799 800-999 >=1000

The Midland Drilled Plenty of Low Quality Vertical Wells (count of oil wells drilled in 2014 YTD by oil IP)

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<300 300-499 500-799 800-999 >=1000

Over 85% of the oil wells drilled in the Midland in 2014 had oil IPs < 300 b/d, as did 55% of the oil wells across six shale plays (the Bakken, Eagle Ford, Delaware, Midland, Niobrara and Mississippian Lime). Even if we simply focus on horizontal wells, the Midland, Niobrara and Mississippian Lime all had over 50% of the 2014 oil wells drilled come in with oil IPs below 300 b/d.

Eagle Ford Dominated Oil Wells Drilled, But Still Contained Many Sub-Par Results (count of horizontal oil wells drilled in 2014 YTD by oil IP)


14


01002003004005006007008009001000

5557596163656769717375

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11A

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Dir/Vert Horizontal Dry Gas Prod (LHS)

A Repeat of the Natural Gas Story Is Unlikely

Despite Rig Declines in 2012, Dry Gas Production Grew YoY (LHS: Dry gas production, Bcf/d; RHS: Gas Rigs)

Source: EIA, Baker Hughes, Morgan Stanley Commodities Research

Rig Efficiency And New Plays Drove Most of the Production and Rig Count Disconnect (LHS:Wtd avg horizontal IP for Marcellus, Haynesville, Barnet & Eagle Ford, Mcf/d; RHS: wtd avg wells/rig/month

Source: HPDI, Morgan Stanley Commodities Research

0.6

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3,400

3,600

3,800

4,000

4,200

4,400

4,600

1Q11

2Q11

3Q11

4Q11

1Q12

2Q12

3Q12

4Q12

1Q13

2Q13

3Q13

4Q13

HZ IP (Mcf/d) HZ wells/rig/mo

The natural gas price decline of 2012 and subsequent production response offers parallels to oil. Initially, production fell hard in 1Q12 as prices dropped to low’s of $2/MMbtu. Total gas rigs fell 50% in 2012 and horizontal rigs fell 47%. However, production continued to grow.

Delayed producer responses and coring-up kept supply from declining dramatically despite uneconomic prices. The Barnett Shale is a good case-study. Production rates improved 28% in 2012 vs 2011 and drill days fell 26% from 110 days to just 81.

Similarly, we have seen large gains in rig efficiency and sometimes IPs as we look across natural gas plays. Such an event is possible in oil, but we would argue that oil is a different molecule that is further along in its maturity than 2011 natural gas.

What was different about gas? Oil has few of the advantages that unfolded in natural gas. 1) A new low cost resource opened up (Marcellus). 2) IPs went up marginally, but this pulled up the avg in recent years. 3) Rig efficiency rose as we went away from HBP drilling, ramped up pad drilling, and changed some techniques. 4) Falling backlogs and new infrastructure have supported production more than we thought. 5) Associated gas and wet gas were marginally helpful too.


15


Brent Structure Is Not As Distressed At It Was In 2008/09 (Prompt Brent 1-2 structure, $/bbl)


In 2008/09 the Call on OPEC Collapsed with Demand; Today’s Call is High (Crude oil specific Call on OPEC & Stocks, mmb/d)

However, This Is Not 2008/09 or 1986 2008/09 was a demand shock, this is a self-inflicted crisis. In 2008, demand evaporated after the Lehman bankruptcy, sending global crude demand spiraling down. The call on OPEC+stocks fell from nearly 32 mmb/d in Jan-08 (>31 mmb/d pre-Lehman) to ~28 mmb/d for much of 2009. This rapid shift left OPEC overproducing and created an inventory overhang that took until late 2010 to work off. In contrast, the crude only Call on OPEC+stocks was expected to fall towards 30.0 to 30.2 mmb/d in 2015 prior to the recent sell off, and now looks like it will approach 30.5 mmb/d in our base case.

If OPEC wanted to intervene, prices could still be in the $90+/bbl range for Brent. The selloff this summer/fall was sparked by low refinery runs and then compounded by the return of Libya – not all that different from the 2012 correction. If OPEC were to accommodate markets in 2015 as they have in past periods, prices would trade much higher (esp. on a constant currency basis). At $90/bbl, we were expecting a mere 800 kb/d imbalance in 2015.

Physical markets do not show the same level of stress. Currently, physical markets show some signs of improvement. While fundamentals could change, we see several key differences vs. 2008. 1) The deep contango is missing: The flood of oversupply sent Brent prompt structure near $3 contango in 2008/09 to cover extreme floating storage costs. By comparison structure is ~$1.11/bbl today with no sign of floating storage 2) Spare capacity remains low: In 2008/09, a major outage would have only helped to close the gap, given excess OPEC capacity. Today, there is very little spare capacity. A large outage would first clean up the market, but there is little ability to offset any squeeze beyond that point.

Sources: Bloomberg, Morgan Stanley Commodity Research

27

28

29

30

31

32

33

Jan-

08M

ay-0

8Se

p-08

Jan-

09M

ay-0

9Se

p-09

Jan-

10M

ay-1

0Se

p-10

Jan-

11M

ay-1

1Se

p-11

Jan-

12M

ay-1

2Se

p-12

Jan-

13M

ay-1

3Se

p-13

Jan-

14M

ay-1

4Se

p-14

Jan-

15M

ay-1

5Se

p-15

MS estimates

Crude only Call on OPEC+Stocks

collapsed in 08/09

The crude Call on OPEC hasn't

changed much

-$3.00

-$2.00

-$1.00

$0.00

$1.00

$2.00

$3.00

Jan-

08M

ay-0

8Se

p-08

Jan-

09M

ay-0

9Se

p-09

Jan-

10M

ay-1

0Se

p-10

Jan-

11M

ay-1

1Se

p-11

Jan-

12M

ay-1

2Se

p-12

Jan-

13M

ay-1

3Se

p-13

Jan-

14M

ay-1

4Se

p-14


16


27.027.528.028.529.029.530.030.531.031.532.0

1Q20

14

2Q20

14

3Q20

14

4Q20

14e

1Q20

15e

2Q20

15e

3Q20

15e

4Q20

15e

Implied Call on OPEC IEA Call on OPEC Crude + Stock ∆

OPEC Crude Production Call on OPEC Crude + Stocks

Ignoring the Stocks in the Call on OPEC+Stocks Can Overstate the Issue

IEA Liquids Balance Fails to Capture True Crude Oil Dynamics (Various Calls on OPEC and OPEC production, mmb/d)

An Oversupply Problem Is Emerging, But The Market Is Overestimating Its Magnitude We see a modest oversupply developing by mid-2015 with no intervention. While any degree of oversupply is negative, talk of a 1.5-2.0 mmb/d oversupply far overstates the issue. We believe much of this misperception comes from three areas: 1) A need to explain the large selloff. 2) Reliance on a fundamentally flawed IEA liquids balance that fails to properly capture true black oil dynamics. 3) A misunderstanding of the “Call on OPEC” and a lack of appreciation for normal seasonal inventory changes.

The traditional IEA balance is fundamentally flawed. By treating all hydrocarbons as fungible, this balance ignores the nuances and drivers of the industry. Refiners are the real consumer of crude oil, and will consume crude and shift yields to maximize profits and supply the most constrained product. As a result, crude oil supply and demand can vary wildly from products and/or IEA balance figures.

Most analysts forget the stocks in the Call on OPEC+Stocks. The only way we can see a “large oversupply” is by looking at current OPEC production vs. the Call on OPEC, which appears large in 2Q15. However, the call on OPEC is really the Call on OPEC + stock changes. Normal seasonality is for stocks to build during this period as refiners move into maintenance. That’s why OPEC production is not as volatile as the “call.”

We use a true crude oil balance, which shows healthier crude demand and a modest oversupply developing that can be corrected. An eventual oversupply will keep pressure on prices, but we don’t see anything close to the 2008-like situation emerging. Extreme bearishness also ignores a number of feedback loops or offsets that could occur at lower prices.

(5Y Average Quarterly Stock ∆, Globally Implied and OECD, mmb/d)


(2.0)

(1.5)

(1.0)

(0.5)

0.0

0.5

1.0

1Q 2Q 3Q 4Q

5Y Avg Crude Stock ∆ - Global implied 5Y Avg Total Oil Stock ∆ - Global implied

5Y Avg Crude Stock ∆ - OECD Industry 5Y Avg Total Oil Stock ∆ - OECD Industry



17


-1,200-1,000

-800-600-400-200

0200400600800

1Q20

11

2Q20

11

3Q20

11

4Q20

11

1Q20

12

2Q20

12

3Q20

12

4Q20

12

1Q20

13

2Q20

13

3Q20

13

4Q20

13

1Q20

14

2Q20

14

3Q20

14

OECD Total Products OECD 3 Main ProductsOECD All Other Products

-

200

400

600

800

1,000

1,200

1,400

(200)

(100)

0

100

200

300

400

500

600

700

$50

$60

$70

$80

$90

$100

Global Product Demand Sensitivity vs. $90 BrentOECD Product Demand Sensitivity vs. $90 BrentEst. Global Product Demand Growth (RHS)

OECD Demand for Key Transport Fuels Is Strong; Other Products Are Weak (YoY ∆ in demand, kb/d)

Note: Assumes 93 average DXY for 2015 and MS GDP est. Sources: Bloomberg, IEA, IMF, Morgan Stanley Commodity Research

Product Demand Will Be Higher At Lower Price Points (left: product demand ∆ vs. $90 Brent baseline; kb/d; right: YoY ∆ in product demand, kb/d)

Demand Will Likely Prove Better Than Expected Models imply nearly 300 kb/d of incremental product demand with crude oil at $70/bbl vs. $90/bbl. Crude runs should also benefit, potentially in a disproportionate manner, as more of the stimulus is likely to come from more constrained transportation fuels.

Historically, OECD demand is very price elastic. GDP is the major driver of crude demand in models, but prices matter too, especially in the OECD. Elasticity will be lower this cycle as some non-OECD nations have discussed using low prices as an opportunity to unwind subsidies. Subsidies also limit the passthrough to EM consumers. However, the OECD can be quite elastic and represents the majority of upside demand revision potential.

Transport fuels, which drive crude demand, are surprisingly healthy and most likely to be stimulated. We find there is a much stronger association between demand for high value transport fuels and refinery crude demand than there is for headline products. Much of the product weakness this year came from OECD ancillary products such as fuel oil, other gasoil (heating and spec issues), and other products.

Source: IEA, Morgan Stanley Commodity Research


18


-15%

-10%

-5%

0%

5%

10%

15%

20%

25%

30%

35%

Jan-

12M

ar-1

2M

ay-1

2Ju

l-12

Sep-

12No

v-12

Jan-

13M

ar-1

3M

ay-1

3Ju

l-13

Sep-

13No

v-13

Jan-

14M

ar-1

4M

ay-1

4Ju

l-14

Sep-

14No

v-14

Brazil India China (inv-adj)

20

22

24

26

28

30

32

Jan-

2000

Aug-

2000

Mar

-200

1O

ct-2

001

May

-200

2D

ec-2

002

Jul-2

003

Feb-

2004

Sep-

2004

Apr-2

005

Nov

-200

5Ju

n-20

06Ja

n-20

07Au

g-20

07M

ar-2

008

Oct

-200

8M

ay-2

009

Dec

-200

9Ju

l-201

0Fe

b-20

11Se

p-20

11Ap

r-201

2N

ov-2

012

Jun-

2013

Jan-

2014

Aug-

2014

U.S. Refinery Yield of Distillate Fuel Oil (Percent)12 per. Mov. Avg. (U.S. Refinery Yield of Distillate Fuel Oil (Percent))

Crude Demand and Product Demand Rarely Align

Rising Distillate Yields Were A Headwind For Crude Demand in Recent Years (US diesel yield, %)

Sources: IEA, BP, EIA, China Customs, ANP, Thomson Reuters, Bloomberg, Morgan Stanley Commodity Research

Markets May Be Too Focused on Headline Product Demand Crude demand is more important than product demand. The end market for crude oil is a refinery, not a gasoline engine. As we’ve outlined in the past (Crude Oil: Near Term Fundamentals Not As Bad As Suggested (30 Nov 2014)), crude demand is not equivalent to product demand for a number of reasons. In fact, crude demand had been far weaker than product demand since the mid-2000s given rising distillate yields with new investment, falling refinery utilization (which allows refiners to run more efficiently on the margin), rising other liquids demand (e.g. biofuels), processing gains and growing demand for NGLs, etc. These headwinds have now eased.

Crude demand is now improving faster than product demand. 2014 will mark the first year since the early 2000s that crude runs outpace product demand. Crude demand grew at 2X the rate of product demand in 2014, and should trend closer to product demand in the future.

The composition of product demand is as important as the headline. Refiners run to maximize profitability and produce the most constrained products, which tend to be the transportation fuels. Currently, product demand weakness is coming from less valuable or important products, a trend that is likely to continue. Transportation fuels remain healthy, with gasoline in particular, growing well in both the OECD and non-OECD.

-2,000

-1,500

-1,000

-500

0

500

1,000

1,500

2,000

2,500

3,000

1984

1985

1986

1987

1988

1989

1990

1991

1992

1993

1994

1995

1996

1997

1998

1999

2000

2001

2002

2003

2004

2005

2006

2007

2008

2009

2010

2011

2012

2013

2014

e

Product - Crude YoY Product Demand YoY Refinery Throughput

(YoY ∆ in total product demand and refinery throughput, kb/d)

EM Gasoline Demand Growth Is Robust (YoY change in gasoline demand, %)

https://ny.matrix.ms.com/eqr/article/webapp/1b1d809e-7534-11e4-b425-7f75cf12bb5f?ch=rpext

https://ny.matrix.ms.com/eqr/article/webapp/1b1d809e-7534-11e4-b425-7f75cf12bb5f?ch=rpext


19


Modest Demand Growth, Capacity Additions A Structural Challenge For Refining Margins and Product Markets

Source: IEA, BP, Morgan Stanley Commodity Research

In Our Base Case, Refining Utilization Should Rise As Capacity Additions Slow

An overbuilding of refining capacity is resulting in structurally lower refining margins. Although product demand remains healthy, current levels of refining capacity are too high for the current level of demand. If all these refiners were to run at the same time, product markets would be severely oversupplied.

Margins must price marginal refiners out of the market on a consistent basis. Refining utilization is now at its lowest level since the mid-1980s, and yet product markets are generally oversupplied. Given the abundance of refining capacity globally (and which continues to grow), product markets must price at a level to limit product production on average. This can keep product cracks lower than they otherwise would be.

The build out of refining capacity will continue. Many non-OECD countries are looking to add refining capacity, often times when economics would say otherwise. Excess capacity and responses to economic signals could add to seasonal volatility.

Rationalizing refining capacity is difficult. Although some refineries have closed in the OECD, permanently closing refineries is difficult. Some key reasons: 1) Integrated ownership; 2) Sovereign concerns (i.e. should France not have a refinery?); 3) Infrastructure problems (some refineries are needed to supply domestic markets given lack of product import capacity); 4) opportunistic buyers (see PADD 1 and PetroPlus)

Capacity Additions Should Start To Slow in 2018 (Refinery capacity additions by region, mmb/d) (Global refinery capacity utilization, %)

70%

72%

74%

76%

78%

80%

82%

84%

86%

88%

1981

1983

1985

1987

1989

1991

1993

1995

1997

1999

2001

2003

2005

2007

2009

2011

2013

2015

e

2017

e

2019

e

-1.0

-0.5

0.0

0.5

1.0

1.5

2.0

2.5

2014

2015

2016

2017

2018

2019

OECD Americas OECD Europe OECD AsiaFSU Non-OECD Europe ChinaOther Asia Latin America Middle EastAfrica



20



In Recent Years, Oil Has Been Less Volatile Than Other Commodities

(60-month realized volatility, %)

Volatility Should Be the New Normal Oil markets are without a cartel for the first time in over 50 years, which is inherently destabilizing. Prior to OPEC wrestling control of markets in the 1970s, the US Texas Railroad Commission controlled production and pricing. The loss of monopolistic pricing power could leave oil in a lower incentive price environment, but also leaves oil susceptible to the large swings present in other commodities.

Talk of a new equilibrium price may be premature. Long run incentive prices are challenged, but a number of structural changes are occurring (both bullish and bearish), but cyclical factors should prove more important for prices. Commodities rarely trade at marginal cost and tend to overshoot.

Geopolitics add both a bullish and bearish slant. Black swan events on the bearish side could come from a lifting of Iran sanctions (which looks more likely) or a return of Libya. On the bullish side, Venezuela and Nigeria may struggle to maintain production if this new world persists.

10%

20%

30%

40%

50%

60%

70%

1995

1996

1997

1998

1999

2000

2001

2002

2003

2004

2005

2006

2007

2008

2009

2010

2011

2012

2013

2014

Gas Crude Nickel Palladium

Bullish FactorsUS needs to grow longer termLittle spare capacityOutage risk is higher at low pricesHigher volatility reduces investment appetite.Loss of the OPEC putUS exports/quality – congestionCosts are cyclical – rig rates will recover

BearishCost deflation and forced innovationInventory overhangUSD/international costsPrisoner’s dilemma and problem of perceptions and faith in long-term oilNOCs/OPEC growth and continuing to investGrowing risk of sanctions relief for Iran

New Bullish and Bearish Structural Problems for Oil Markets (60-month rolling volatility, annual %)


21


29.0

29.5

30.0

30.5

31.0

31.5

32.0

32.5

(600) (400) (200)

- 200 400 600 800

1,000 1,200 1,400 1,600

2008

2009

2010

2011

2012

2013

2014

2015

2016

2017

2018

2019

2020

Est. Crude Oil Supply Growth before OPEC CrudeCrude Only Call on OPEC+StocksOPEC Crude Production

forecast

Assumes MS base case price forecast and limited loss of non-US investment. Sources: IEA, JODI, Morgan Stanley Commodity Research estimates

Long Run Balances Have Suggested More Supply Is Needed by 2018+ (left: YoY ∆ in non-OPEC crude supply, kb/d; right: Crude-specific Call on OPEC+stocks and production, mmb/d)

Lower Prices Today Can Setup For Higher Prices Later The lower and longer prices fall in the interim, the greater the long run impact and risk of higher prices as a reaction.

A lack of investment could result in much higher prices later in the decade. Oil faces long run challenges, but healthy supply growth is still required to balance the market. Based on modest demand growth assumptions, we estimated the market required ~30 mmb/d of gross additions from 2014-2020 to both offset natural declines and support demand growth. Without adequate investment, oil demand could far outstrip supply in a few years.

Outside the US, supply growth cannot return quickly once curtailed. Many of these additions are high cost and risky investments with long lead times, particularly later in the decade. These projects will struggle to respond quickly and return with any improving price signal, creating the risk that prices could overshoot to the upside. If anything, removing the “OPEC put” should raise the hurdle rate required on oil projects, which may require even high prices for higher cost and risky projects. While a supply crunch would be short term bullish, the resulting high prices would be long run destructive for oil demand.

As prices fall, outage risks rise, particularly from financially stressed nations that cannot maintain subsidies. As subsidies are lifted, the risk of civil unrest tends to rise, putting production at risk. With little spare capacity today, the market has few options to deal with a large outage. Creating a world where OPEC needs to produce at such high levels leaves the market increasingly vulnerable to shocks and increased volatility.

$0

$20

$40

$60

$80

$100

$120

$140

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

Permian, US

W. Qurna 2, IQ

Eagle Ford, US

Bakken, US

Kearl, CA

Canadian In-Situ Oilsands Projects

Canadian Mining Oilsands Projects

Necessary Additions Are At Risk, Risking Much Higher Prices Later (y-axis: Marginal breakeven price assuming 10% hurdle rate on a Brent-equivalent basis, $bbl, x-axis: incremental liquids production added 2014-2020, mmb/d))

Sources: Rystad, Wood Mackenzie, Morgan Stanley Commodity Research


22


Sources: BP, IEA, Morgan Stanley Commodity Research

Saudi and OPEC Production Dropped Significantly in the Mid 1980s, Leaving Plenty of Spare Capacity (left axis: OPEC crude production, mmb/d; right axis: Saudi crude production, mmb/d)

1986: History Rhymes, But Doesn’t Repeat Rather than a repeat of 1986, volatility is likely the new norm. We continue to hear comparisons between OPEC’s recent actions and those of 1986. While there are similarities, we don’t believe the oil market has entered a new decade-long cycle of drastically lower prices. Rather, we see a market where elevated volatility and boom-bust cycles will likely become the norm.

Today’s situation is different in many crucial ways: 1) Saudi Arabia didn’t lift production this time, OPEC just failed to cut. 2) Spare capacity was >15 mmb/d in 1986. Today, practical spare capacity is ~1 mmb/d with elevated risk of outages and civil unrest. 3) Lower cost sources of untapped production were available in the 1980s. 4) The market is more reliant on long lead time projects (e.g. offshore) in challenging regions, and the breakdown of service costs has changed. 5) While shale increases US supply elasticity, the globe has a larger production base to replace with arguably higher decline rates (offshore, shale) relative to conventional onshore that represented a large share of production in the 1980s.

Supply swings in a few key countries explain a surprising amount of the oil “cycles” of the past 30 years. We continue to hear incorrect narratives about 1986, as well as oil history overall. Iraq, Russia and Saudi Arabia supply were responsible for a large part of many oil cycles of the past 30 years. Non-OPEC production (ex. Russia) has been more consistent and followed normal cycles.

3

4

5

6

7

8

9

10

11

10

15

20

25

30

35

1975

1977

1979

1981

1983

1985

1987

1989

1991

1993

1995

1997

1999

2001

2003

2005

2007

2009

2011

2013

OPEC (LHS) Saudi Arabia (RHS)

Swings in Russia and Iraq Production Were Large Contributors to the Last 30 Years of Price Swings (Liquids supplies by region, mmb/d)


-2000-1500-1000

-5000

50010001500200025003000

1985

1987

1989

1991

1993

1995

1997

1999

2001

2003

2005

2007

2009

2011

2013

Total OPEC Non-OPEC Non-OPEC ex. FSU


23


3.70

2.42

1.87

0.44 0.510.11 0.10 0.18 0.02

0.0

0.5

1.0

1.5

2.0

2.5

3.0

3.5

4.0

Iraq

Vene

zuel

a

Nig

eria

Liby

a

Arge

ntin

a

Yem

en

Suda

n

Sout

h Su

dan

Syria

Almost No OPEC Spare Capacity to Offset a Major Outage (OPEC spare capacity as of Dec 2014, kb/d)

Sources: IEA, Morgan Stanley Commodity Research

Significant Share Of Global Oil Supply Resides in Challenging Areas (Dec 2014 global crude supply from at-risk countries, mmb/d)

By Comparison, Supply Outage Risk Is Rising, Reinforcing Volatility Will be the New Norm We worry most about countries that cannot support gasoline subsidies as those directly impact consumers. We’ve never been a big advocate of OPEC balanced budget math as driving oil markets or behavior. However, Venezuela and Nigeria are exceptions to the rule. In these countries, populations have become used to low gasoline prices (esp in Venezuela), but the country is dependent on international supplies. If oil prices decline to levels such that subsidies cannot be supported and will need to be lifted, civil unrest and crude production disruptions could result. Both Venezuela and Nigeria have a history of protests over gasoline pricing changes.

Lower prices increase the risk of a major outage. This is possible longer term if governments cannot provide basic services, leading to civil unrest and disruptions, especially as ~12% of oil production is in economically unstable regions.

If supply does go offline, there is little spare capacity to meet it. Saudi Arabia holds the vast majority of spare capacity, but it is unlikely to use it due to the need to manage reservoirs. They are currently producing near historical maximums and never went near reported spare capacity in prior crises. Furthermore, much of this spare capacity is not effective, especially in Libya as it could take months-years to bring that capacity into production given the flight of oil ex-pat workers and damage to fields.

Source: IEA, Morgan Stanley Commodity Research *In Libya, we assume 1.4 mmb/d of capacity .

510435

945

2,780435

3,215

0 130 60

960 180

4,545

0500

1,0001,5002,0002,5003,0003,5004,0004,5005,000

To M

ax K

SA

Prod

uctio

n

Oth

ers

Spar

e

Rea

listic

Cap

acity

Saud

i Ara

bia

Spar

e C

apac

ityO

ther

Effe

ctiv

eSp

are

Effe

ctiv

e S

pare

Cap

acity

Iraq

Nig

eria

Iran

Liby

a*

Vene

zuel

a

Rep

orte

d Sp

are

Cap

acity


24


Global Overview Despite Rising Project Costs, Upstream Capex Growth Expected to Decelerate

Source: Rystad Energy, Morgan Stanley Commodity Research

Global Oil Capex Is Likely To Slow In the Medium Term, But Should Pick Up Later (Oil field capex, millions $)

Capital investment set to slow in response to low prices. Oil capex grew rapidly in the 2000s in response to higher prices. With the recent decline, that trend could reverse in the medium term. However, we would still expect capex to grow longer term in order to meet a conservative level of demand and support supply growth.

Mix of investment shifting: Exploration accounting for a smaller share of capex. With rising US onshore production growth largely from proven reservoirs, many firms are trading in exploration risk for commodity price risk. As a result, there are now likely fewer high risk exploratory wells, allowing exploration to decline as a share of total capex. Moreover, with a more manufacturing-like process in US shale, development and well capex are rising as a percentage of total capex. The number of wells needed to maintain US production momentum only grows as production grows. Finally, capex categories such as modification capex (EOR) are losing share globally as well as EOR drives less production growth in our forecast period.

Cyclical or secular deceleration? Falling service costs and lower oil prices should reduce investment and the overall cost of projects. However, one could argue that such savings are only cyclical. As prices recover, demand for oil services will rise as well.

Exploration Capex Is Most At Risk In Low Price Environment (% share of total oil capex, %)

0

100

200

300

400

500

600

700

800

2000

2001

2002

2003

2004

2005

2006

2007

2008

2009

2010

2011

2012

2013

2014

2015

e20

16e

2017

e20

18e

2019

e20

20e

2002-2014:15% CAGR

2014-2016e:-2% CAGR

2016e-2020e:6% CAGR

29%

31%

28%

29%

27%

31%

28%

28%

27%

25%

22%

22%

23%

24%

23%

37%

37%

40%

41%

45% 44%

44%

44%

45%

45%

47%

47%

48%

48%

49%

20%

18%

18% 17%

17%

16%

17%

17%

18%

19%

18%

16%

15%

14%

13%

11%

11%

11%

10%

8% 7% 8% 8% 9% 9% 11%

13%

12%

12%

13%

0%10%20%30%40%50%60%70%80%90%

100%

2000

2001

2002

2003

2004

2005

2006

2007

2008

2009

2010

2011

2012

2013

2014

Development Capex Well CapexModification Capex Subsea Brownfield CapexExploration Capex

Source: Rystad Energy, Morgan Stanley Commodity Research


25


0%

10%

20%

30%

40%

50%

60%

70%

80%

DevelopmentCapex

Well Capex ModificationCapex

SubseaBrownfield Capex

Ultra deepwater (1500+ meter) Deep water (125-1500 meter)Shelf (to 125 meter) Land

0%

10%

20%

30%

40%

50%

60%

70%

80%

90%

100%

DevelopmentCapex

Well Capex ModificationCapex

SubseaBrownfield Capex

Conventional Arctic Oil sands (mining) Oil sands (in-situ)Extra heavy oil Tight liquids plays Shale oil plays


Deepwater Projects Have Higher Proportion Of Development Capex (proportion of capex costs by type, %)

Breakdown of Capex Spending: Saving on Rigs Should Not Be A Large Savings for Many Projects


Unconventional Production Has A Much Higher Share Of Well Capex (proportion of capex costs by type, %)

For US shale, 60-70% of the cost is now in completion. Well capex is the majority of US well cost. However, drilling efficiencies have materially lowered the burden from running rigs. Hence, fracking and completion services should be vulnerable and a target of US E&Ps.

Deep water projects tend to be more exposed to facility development. Drilling costs can be material, but these savings won’t dramatically improve the economics of an offshore project.

Exploration capex: Costs incurred to find and prove hydrocarbons: seismic, wildcat and appraisal wells, general engineering costs, based on reports and budgets or modelled.

Development capex: Greenfield investments for the facility. This cost type drives the investments for the hull/leg, topsides and subsea structures.

Well capex: capitalized costs related to well construction, including drilling costs, rig lease, well completion, well stimulation and commodities.

Modification capex: Larger brownfield investments for the facility that is not expensed as an opex. This can be EOR, new wellhead platform or topside module. Brownfield investments related to drilling and completion of wells are included under Well Capex.

Subsea brownfield capex: Late life investments for subsea structures. Brownfield drilling programs for fields with need for subsea units will drive the Subsea Brownfield Capex.


26


$0

$20

$40

$60

$80

$100

$120

$140

-$20

-$15

-$10

-$5

$0

$5

$10

$15

$20

Jan-

00

Jan-

01

Jan-

02

Jan-

03

Jan-

04

Jan-

05

Jan-

06

Jan-

07

Jan-

08

Jan-

09

Jan-

10

Jan-

11

Jan-

12

Jan-

13

Jan-

14

Jan-

15

USD impact on reported price Brent - Constant Currency

Oil Prices Have Been Less Volatile on a Constant Currency Basis (left: USD translation impact on Brent, $/bbl; right: Brent – con .currency, $/bbl)

Sources: Morgan Stanley FX Strategy Research estimates

MS FX Strategy Anticipates a Continued Strengthening of the USD

A Stronger USD Will be a Headwind, But Less So At Low Price Levels The USD has moved beyond our original expectations. While the beta to the USD can vary over time as it’s only one of many variables in crude pricing, we can’t ignore the negative trading relationship with crude prices. While this could simply be a factor for macro models, the inverse relationship does have some fundamental justification. Adjusting for the stronger USD outlook forces us to trim all of our forecasts in nominal terms.

On a constant currency basis, prices have not fallen as far. If we assume there is a fully pass through over time on the trade-weighted USD, we find correlations with fundamentals are even higher. Moreover, we find less volatility during some recent periods if we smooth out for changes in currency. As a result, we have a bias towards forecasting prices on a constant currency basis.

Expectations for a stronger USD could continue to weigh on prices and recovery. Our FX team sees the DXY moving towards 95 by 2H15 before stabilizing. Under such a scenario, even a $90/bbl price in 2012 USD terms would translate into $76/bbl at a 95 DXY level. While this likely overstates the headwind, and US consumers will still realize a lower cost burden, globally, the stronger USD does lift the local price of oil and project economics.

That said, the need to support US production provides some offset. A strong USD effectively makes the US less competitive by lifting relative costs. US producers will not see any translation benefit. Given US growth is critical over the long run to keep supply and demand in balance, WTI needs to maintain a level over the medium term where US producers can invest, regardless of FX. Thus, the USD impact at lower oil prices is more muted.


PeriodMS Dollar

IndexEUR / USD

USD / JPY

USD / CAD

1Q14 80.10 1.38 103 1.11 2Q14 79.78 1.37 101 1.07 3Q14 85.94 1.26 110 1.12 4Q14 89.12 1.24 120 1.13 1Q15 91.17 1.20 122 1.14 2Q15 92.57 1.18 123 1.15 3Q15 94.64 1.14 126 1.16 4Q15 95.36 1.12 127 1.17 1Q16 95.26 1.12 126 1.19 2Q16 95.08 1.13 125 1.20 3Q16 94.77 1.14 123 1.21 4Q16 95.17 1.15 125 1.22


27


At Current Diffs, The US Risks Attracting Too Many Imports (Various crude diffs vs. Mars, $/bbl)

Could WTI Become the New Global Benchmark? The US needs to grow longer term. In order to meet a modest demand growth assumption, prices must incentivize relatively more expensive sources of supplies. Without US growth (or some equivalent), the oil balance becomes tight relatively quickly. Thus, US production needs to be supported to at least some level, which will require higher WTI pricing (although perhaps not too high). At today’s economics, that incentive price would be closer to $80/bbl, though we expect that to fall.

Even if the US can produce it, exports are still a question. Even though we forecast material US production growth longer term, policy changes may not keep up. Although the US Department of Commerce has moved forward in approving lightly-processed condensate exports (~400 kb/d), and possibly Mexico swaps, an all-out lifting of the crude export ban still appears unlikely given the sensitivity of gasoline prices for consumers. If the US exhausts its export opportunity to Canada and Mexico (via swaps), this would serve to lift Brent prices.

Even near-term, the US faces some congestion. US physical markets have weakened from a position of strength earlier this year to a sizable contango. Inventories are higher YoY heading into peak USGC refinery maintenance. At the same time, diffs are attracting imports and shutting down exports or Jones Act opportunities. Prices may need to weaken to open options.

Sources: Bloomberg, Plattts, Morgan Stanley Commodity Research

18

19

20

21

22

23

24

25

26

27

28


2015 2014 2013 5-Year Avg

PADD IIII Crude Days-of-Supply Quietly Building Again (PADD III crude days of supply, days)

Sources: DOE, Morgan Stanley Commodity Research

-$10.00

-$8.00

-$6.00

-$4.00

-$2.00

$0.00

$2.00

$4.00

$6.00

$8.00

$10.00

1-Ja

n-14

15-J

an-1

429

-Jan

-14

12-F

eb-1

426

-Feb

-14

12-M

ar-1

426

-Mar

-14

9-A

pr-1

423

-Apr

-14

7-M

ay-1

421

-May

-14

4-Ju

n-14

18-J

un-1

42-

Jul-1

416

-Jul

-14

30-J

ul-1

413

-Aug

-14

27-A

ug-1

410

-Sep

-14

24-S

ep-1

48-

Oct

-14

22-O

ct-1

45-

Nov

-14

19-N

ov-1

43-

Dec

-14

17-D

ec-1

431

-Dec

-14

14-J

an-1

5

Dubai Cabinda Arab Med Basrah Urals

Mars at a discount

Mars at a premium


28


2015: Challenges Grow, But Options Remain If The Price Is Right By 2015, higher production and lower imports will leave fewer outlets for US production growth. • Consensus is that the US will need exports to prevent a

collapse in WTI • However, the true view is more nuanced. • Must think creatively about solutions – producers and traders

will!

Framing The 2015 WTI Debate: 1. US exports would help, but not a panacea.

2. The 2015 situation may not be as dire as expected, especially in 1H15.

• More levers are available or opening for shippers/producers to pull.

3. Lower prices open new options for light crude absorption.

4. Maya may create a sustainable floor for LLS pricing.

314

500

277 234

300

525

2,150

140 200

653

3,143

-

500

1,000

1,500

2,000

2,500

3,000

3,500

Wat

erbo

rne

Impo

rts

Con

dens

ate

Split

ters

Can

Impo

rtsex

US

Can

adia

nO

ffsho

re

Can

. Lt I

mp.

Padd

s 2+

4

Alas

kaPr

oduc

tion

Acce

ssib

leLi

ght

Util

izat

ion

Mex

ico

Swap

s

Est.

Med

Blen

d

Ligh

tPo

tent

ial*

There Are Options For Light Crude, But Only With Proper Pricing And Infrastructure (light crude oil imports/demand assuming no infrastructure constraints, kb/d)

100

366

277

234

300 -

1,277

59 150

396

1,883

-

200

400

600

800

1,000

1,200

1,400

1,600

1,800

2,000

Wat

erbo

rne

Impo

rts

Split

ters

/To

pper

s

Can

Impo

rtsex

US

Can

adia

nO

ffsho

re

Can

. Lt I

mp.

Padd

s 2+

4

Alas

kaPr

oduc

tion

Acce

ssib

leLi

ght

Util

izat

ion

Mex

ico

Swap

s

Est.

Med

Blen

d

Ligh

tPo

tent

ial*

2015 Levers Should Be Able to Offset US Growth (Incremental light crude oil imports/demand options for 2015, kb/d)

Source: DOE, Company Data, Morgan Stanley Commodity Research


29


x

HOUSTON

ST. JAMES

EUROPE

4-$7/bblEast Coast

2-$3/bblEast Canada

~2/bblEurope

Plenty of Challenges to the Export Argument We expect incremental changes such as crude swaps or condensate exports at some point, but even these changes face headwinds.

Headwinds for US Crude Exports: A full lifting of the export ban would require Congress. This is politically difficult and may require a deep discount in prices. Easing the ban through redefining refined products may be a more politically savvy solution.

No guarantee for a permanent easing of the ban. Producers and investors may have little confidence that another administration won’t overturn the ruling. May still constrain investment.

Jones Act and crude exports are linked. Beyond political challenges, the Jones Act will ensure that US East Coast refiners pay more for US crude than Canadian and European refiners in an export scenario.

Condensate exports may not solve much. The economics and market for processed condensate and naphtha may not be as deep as expected. Europe is long naphtha, Asia has cheaper sources and prices are already weakening. Blending domestically may be more attractive.

Jones Act Issues Distort Crude Export Economics

Source: Bloomberg, Company Data, Morgan Stanley Commodity Research estimates

(transport economics, $/bbl)

-

200

400

600

800

1,000

1,200

1,400

Jan-

08

Jul-0

8

Jan-

09

Jul-0

9

Jan-

10

Jul-1

0

Jan-

11

Jul-1

1

Jan-

12

Jul-1

2

Jan-

13

Jul-1

3

Jan-

14

Americas Europe FSU Africa OPEC/Middle East Asia Other

US Naphtha Exports to Asia Will Need to Compete Against Advantaged Suppliers (OECD Asia Oceania naphtha imports, kb/d)



30


Morgan Stanley Global Crude Oil Balance

Sources: IEA, JODI, Morgan Stanley Commodity Research estimates

CRUDE-ONLY BALANCE 2013 Jan-14 Feb-14 Mar-14 Apr-14 May-14 Jun-14 Jul-14 Aug-14 Sep-14 Oct-14 Nov -14 Dec-14 2014 Jan-15 Feb-15 Mar-15 Apr-15 May-15 Jun-15 Jul-15 Aug-15 Sep-15 Oct-15 Nov -15 Dec-15 2015Days 365 31 28 31 30 31 30 31 31 30 31 30 31 365 31 28 31 30 31 30 31 31 30 31 30 31 365

REFINERY THROUGHPUTOECD Crude Runs 36.6 36.5 36.4 35.9 36.6 36.2 35.7 37.6 38.3 37.1 36.2 36.8 37.9 36.8 37.3 36.8 36.5 36.8 36.5 37.0 37.6 37.5 36.6 36.4 37.4 37.8 37.0

YoY (0.4) (0.0) (0.1) (0.2) 0.6 0.5 (1.9) (0.4) 0.5 0.8 1.8 0.1 0.7 0.2 0.8 0.4 0.6 0.2 0.2 1.3 0.0 (0.7) (0.5) 0.2 0.6 (0.1) 0.2

Non-OECD Crude Runs 39.2 40.5 40.6 40.7 39.8 40.2 40.9 39.8 40.6 40.2 40.8 41.2 41.4 40.6 41.3 41.7 40.6 39.9 40.5 41.3 41.7 41.8 41.0 40.3 41.2 41.9 41.1YoY 0.9 1.1 1.4 2.7 2.4 2.1 1.4 (0.3) 0.9 0.7 1.5 1.1 0.8 1.3 0.8 1.1 (0.1) 0.1 0.3 0.4 1.9 1.2 0.8 (0.5) (0.0) 0.4 0.5

Global Crude Runs 75.8 77.0 77.0 76.6 76.4 76.4 76.6 77.4 78.9 77.3 77.0 78.0 79.3 77.3 78.6 78.4 77.1 76.7 77.0 78.3 79.3 79.3 77.6 76.7 78.6 79.7 78.1YoY 0.4 1.1 1.3 2.5 3.0 2.6 (0.5) (0.7) 1.4 1.5 3.3 1.2 1.5 1.5 1.6 1.4 0.5 0.4 0.5 1.7 1.9 0.4 0.3 (0.3) 0.6 0.4 0.8

DIRECT CRUDE USETotal Direct Use 0.9 0.8 1.2 0.7 0.9 1.1 1.3 1.3 1.3 1.0 0.8 0.6 0.6 1.0 0.6 0.6 0.6 0.9 1.1 1.2 1.2 1.2 1.1 0.9 0.7 0.7 0.9

YoY (0.1) 0.1 0.6 0.1 0.2 0.1 0.3 0.1 0.0 (0.0) 0.0 (0.1) (0.1) 0.1 (0.2) (0.6) (0.1) (0.0) (0.1) (0.1) (0.1) (0.0) 0.1 0.1 0.1 0.1 (0.1)

Total Crude Demand 76.7 77.8 78.2 77.4 77.3 77.5 77.9 78.7 80.1 78.2 77.8 78.6 79.9 78.3 79.3 79.1 77.8 77.6 78.0 79.5 80.5 80.5 78.6 77.5 79.3 80.4 79.0YoY 0.4 1.2 1.8 2.5 3.2 2.7 (0.2) (0.5) 1.5 1.5 3.3 1.2 1.4 1.6 1.4 0.8 0.4 0.3 0.5 1.6 1.8 0.4 0.4 (0.3) 0.6 0.4 0.7

CRUDE OIL SUPPLYOECD Crude 16.4 17.2 17.4 17.6 17.6 17.4 17.4 17.6 17.5 17.9 18.1 18.0 18.3 17.7 18.4 18.6 18.6 18.5 18.4 18.2 18.2 18.3 18.4 18.5 18.7 18.5 18.4

YoY 0.9 1.1 1.2 1.3 1.3 1.4 1.6 1.1 1.1 1.3 1.6 0.8 1.0 1.2 1.2 1.2 1.0 1.0 1.0 0.7 0.6 0.8 0.5 0.4 0.7 0.2 0.8

Non-OECD Crude 27.3 27.6 27.6 27.4 27.3 27.2 27.5 27.2 27.3 27.5 27.5 27.4 27.6 27.4 27.5 27.4 27.3 27.3 27.2 27.4 27.6 27.3 27.5 27.4 27.4 27.4 27.4YoY 0.0 0.3 0.3 0.3 0.3 0.1 0.1 (0.0) 0.3 0.5 (0.1) (0.2) (0.1) 0.1 (0.1) (0.2) (0.1) (0.1) 0.0 (0.1) 0.4 (0.0) 0.0 (0.1) (0.0) (0.2) (0.0)

Est. Incremental Outages 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 (0.1) 0.0 (0.2) (0.1) 0.0 (0.2) (0.3) (0.2) (0.1)Non-OPEC Crude 43.7 44.8 45.0 45.0 44.9 44.6 45.0 44.8 44.9 45.4 45.6 45.4 45.9 45.1 45.9 46.0 45.9 45.8 45.5 45.6 45.6 45.5 45.9 45.7 45.8 45.8 45.7

YoY 0.9 1.4 1.5 1.6 1.6 1.4 1.7 1.1 1.4 1.8 1.5 0.6 0.9 1.4 1.1 1.0 0.9 0.9 0.9 0.7 0.8 0.6 0.5 0.1 0.4 (0.2) 0.6

OPEC Condensate 2.7 2.7 2.7 2.7 2.7 2.7 2.7 2.7 2.7 2.7 2.8 2.8 2.8 2.7 2.7 2.7 2.7 2.8 2.8 2.8 2.8 2.8 2.8 2.8 2.8 2.8 2.8YoY 0.1 0.0 0.0 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 0.1 0.1 0.1 0.1 0.0 0.0 0.0 0.0 0.0 0.0 0.0

OPEC Crude Production 30.5 30.0 30.5 29.5 29.8 30.2 30.2 30.5 30.3 30.8 30.6 30.4 30.5 30.3 30.2 30.4 30.6 30.7 30.7 30.8 31.0 30.7 30.6 30.5 30.7 31.0 30.7YoY (0.8) (0.4) 0.0 (1.0) (1.0) (0.9) (0.6) (0.5) (0.5) 0.7 0.7 0.8 0.6 (0.2) 0.2 (0.1) 1.0 0.9 0.5 0.6 0.5 0.4 (0.1) (0.1) 0.3 0.5 0.4

Total Crude Supply 76.8 77.5 78.2 77.2 77.4 77.5 77.8 78.1 78.0 78.9 79.0 78.6 79.1 78.1 78.9 79.1 79.2 79.3 78.9 79.2 79.3 79.0 79.3 79.0 79.2 79.5 79.2YoY 0.2 1.1 1.5 0.7 0.7 0.6 1.1 0.7 1.0 2.6 2.3 1.5 1.6 1.3 1.4 0.9 2.0 1.8 1.4 1.4 1.3 1.1 0.4 (0.0) 0.7 0.4 1.1

CALL ON OPECTotal Crude Demand 76.7 77.8 78.2 77.4 77.3 77.5 77.9 78.7 80.1 78.2 77.8 78.6 79.9 78.3 79.3 79.1 77.8 77.6 78.0 79.5 80.5 80.5 78.6 77.5 79.3 80.4 79.0

YoY 0.4 1.2 1.8 2.5 3.2 2.7 (0.2) (0.5) 1.5 1.5 3.3 1.2 1.4 1.6 1.4 0.8 0.4 0.3 0.5 1.6 1.8 0.4 0.4 (0.3) 0.6 0.4 0.7Supply Before OPEC Crude 46.4 47.5 47.7 47.7 47.6 47.3 47.7 47.6 47.6 48.1 48.3 48.2 48.7 47.8 48.7 48.7 48.6 48.6 48.2 48.4 48.4 48.3 48.7 48.5 48.5 48.5 48.5

YoY 1.0 1.4 1.5 1.7 1.7 1.5 1.7 1.2 1.5 1.9 1.6 0.7 1.0 1.4 1.2 1.0 1.0 1.0 1.0 0.7 0.8 0.7 0.5 0.1 0.4 (0.1) 0.7

Call on OPEC Crude + Stocks 30.3 30.3 30.5 29.7 29.7 30.3 30.2 31.1 32.5 30.1 29.5 30.5 31.3 30.5 30.6 30.3 29.1 29.0 29.8 31.1 32.1 32.2 30.0 29.1 30.7 31.8 30.5YoY (0.7) (0.2) 0.3 0.9 1.5 1.2 (1.9) (1.7) 0.0 (0.4) 1.7 0.5 0.3 0.2 0.2 (0.2) (0.6) (0.7) (0.5) 0.9 1.0 (0.3) (0.2) (0.4) 0.3 0.6 0.0

Historical Implied Stock ∆ (0.3) 0.1 (0.1) 0.6 0.5 0.1 (0.8) (1.1) (1.3) (0.8) 0.6 (0.3) (0.6) (0.3) (0.1) (0.0) 0.4 0.4 0.1 (0.5) (0.9) (0.9) (0.4) 0.5 (0.3) (0.5) (0.2)

Implied Call on OPEC 30.0 30.4 30.5 30.3 30.2 30.3 29.4 30.0 31.2 29.4 30.1 30.1 30.7 30.2 30.5 30.3 29.5 29.4 29.8 30.5 31.3 31.2 29.6 29.6 30.5 31.3 30.3YoY (0.2) (0.2) 0.2 1.0 1.8 1.4 (2.1) (1.9) (0.0) (0.5) 1.8 0.4 0.1 0.2 0.1 (0.1) (0.9) (0.8) (0.5) 1.1 1.3 0.0 0.2 (0.5) 0.3 0.6 0.1

STOCK CHANGEImplied Stock ∆ 0.2 (0.3) (0.0) (0.2) 0.2 (0.0) (0.0) (0.6) (2.2) 0.6 1.2 (0.1) (0.8) (0.2) (0.3) 0.0 1.5 1.7 0.9 (0.2) (1.2) (1.5) 0.7 1.4 (0.0) (0.9) 0.2

5Y Median (0.3) (0.2) (0.0) 1.1 0.5 (0.1) (1.3) (1.9) (2.6) (1.6) 1.0 (0.4) (1.0) (0.3) (0.3) (0.0) 0.7 0.2 (0.0) (1.3) (1.9) (2.2) (0.5) 1.2 (0.4) (1.0) (0.2)

Misc to Balance 0.2 (0.3) (0.8) (1.2) 0.3 (0.6) 0.2 (0.0) (1.8) 0.7 0.1 0.3 (0.2) (0.3) (0.3) (0.0) 1.0 1.2 0.6 (0.2) (0.9) (1.1) 0.4 1.0 (0.1) (0.7) 0.15Y Median 0.0 0.4 (1.0) (1.9) (2.2) (2.6) 0.7 1.3 (0.8) 2.1 (1.4) 0.1 (0.3) (0.5) (0.0) 0.8 2.2 0.9 1.2 (0.4) (0.9) 0.7 (0.3) 0.9 (0.4) (0.5) 0.3

OECD Stock ∆ (0.0) (0.0) 0.8 1.0 (0.2) 0.6 (0.2) (0.6) (0.4) (0.1) 1.1 (0.4) (0.6) 0.1 (0.0) 0.1 0.4 0.5 0.3 (0.0) (0.3) (0.3) 0.2 0.4 0.0 (0.2) 0.15Y Median 0.0 0.7 0.3 0.8 0.5 (0.1) (0.2) (0.4) (0.6) (0.1) (0.0) 0.3 (1.1) 0.0 0.5 0.4 0.8 0.5 0.1 (0.2) (0.5) (0.4) (0.1) 0.7 (0.4) (0.9) 0.0

OECD Ending Stocks - mmb 2,240 2,239 2,261 2,292 2,287 2,305 2,298 2,279 2,267 2,265 2,298 2,285 2,266 2,266 2,265 2,268 2,279 2,283 2,288 2,283 2,279 2,272 2,286 2,285 2,288 2,280 2,280Stock Change - mmb (13.9) (0.9) 21.6 31.2 (5.2) 17.9 (7.0) (18.7) (12.2) (2.2) 33.0 (12.4) (19.1) 26.1 (1.4) 1.7 13.7 15.3 9.1 (0.5) (8.4) (10.7) 6.8 13.4 1.3 (5.8) 13.35Y Median ∆ 17.6 22.1 8.1 23.3 15.0 (1.8) (7.1) (13.4) (20.1) (2.6) (1.2) 8.6 (33.1) 12.9 16.8 10.6 23.3 15.0 2.1 (7.1) (16.0) (12.2) (2.2) 20.2 (12.4) (27.8) 17.6


31


Natural Gas


32


1,727

3,819

2,733501 178 558

214 74 23 70

1,000

1,500

2,000

2,500

3,000

3,500

4,000

4,500

5,000

5,500

End

-Mar

ch 1

5

14 in

j

Pro

d

net i

mp

CTG

Sw

itch

MA

TS

Indu

stria

l

Res

iden

tial

Oth

er d

eman

d

End

-Oct

15

2,115

1,727

1,447

$2.50

$3.00

$4.00

$-

$0.50

$1.00

$1.50

$2.00

$2.50

$3.00

$3.50

$4.00

$4.50

0

500

1,000

1,500

2,000

2,500

Bear (Jan-Mar 12) Base (10 yr norm) Bull (Jan-Mar 14)

Executive Summary: Another Challenging Year for Natural Gas

Path To End-Oct 15 – Driven by CTG Switching (US working gas, Bcf)

Mild Dec Has Narrowed Our End-March Range (Left Axis: End March 2015, Bcf, under winter weather scenarios. Right Axis: 2015 FY average price forecast, $/MMbtu

Source: CME, Morgan Stanley Commodities Research

Need for more gas power demand sets up another challenging year. Natural gas prices are low, but poor fundamentals keep us from bring constructive. Robust production growth and much higher end-Mar storage reduce the need for summer 2015 injections. As a result, coal-to-gas economics will need to balance the market. Prices must incentivize enough gas power burn (2.6 Bcf/d YoY in excess of MATS) to limit storage to 3.82 Tcf by end-Oct. The problem is that coal retirements and low PJM prices have reduced the power elasticity, requiring even lower gas prices. That said, much of the bad news appears priced in. In our base case, a $2.95 injection season average should be sufficient, with prices likely to overcorrect in Apr/May.

Weather remains a key variable, but the bull case isn’t compelling. Extreme bullish weather could swing our 2015 outlook as high as $4.00/mmBtu, but a repeat of 2014’s price action is unlikely. Supply levels, reliability, interconnectivity and infrastructure are all much improved, and oil generation costs are lower. We already see much lower NE prices YoY on peak demand days. Moreover, despite starting winter 14-15 with much less storage, US storage has moved into a healthy surplus. In fact, we see almost no scenario where end-Mar storage won’t be significantly higher YoY. Even with a Jan-Mar 14 repeat, we see 1.45 Tcf for end-Mar vs. 857 bcf in 2014.

US production growth is relentless…. US dry gas growth of 4 Bcf/d during much of 2014 may balloon to >5 Bcf/d in early 2015, esp if weather stays mild. Tougher YoY comps will slow growth as the year progresses, but we still see 2-3 Bcf/d of US supply growth for the balance of 2015. NE Infrastructure-led production growth, associated gas (even with lower oil) and moderating declines from mature basins are all helpful.

…While structural demand growth is years away. ~12 GW of coal is due to be retired in 2015, but we see only 1Bcf/d of incremental demand given low NE prices and historically low coal fleet utilization. Industrial, LNG and Mexican exports show slight increases, but not enough to aid balances. Larger demand additions don’t begin until 2017+, even if projects remain on schedule.

Basis problems should spread as infrastructure improves. NE imports could fall to zero year-round by 2016, and until structural demand pull arrives, low NE prices and high power burn will be required. ~34 bcf/d of NE export capacity is planned to commence before 2018, mainly targeting the SE. These pipes should offer some relief to the NE, but also begin to pressure prices in new markets, esp during summer. We will revisit our view on NE basis in more detail in future reports.

Source: EIA, Morgan Stanley Commodities Research

+2.6 Bcf/d YoY in summer requires prices

at ~$3/Mmbtu


33


60

62

64

66

68

70

72

74

Jan-15 Mar-15 May-15 Jul-15 Sep-15 Nov-15

2014 2015

Base 1,727

Bear 2,115

Bull 1,447

500

1,000

1,500

2,000

2,500

3,000

3,500

4,000

Oct-14 Nov-14 Dec-14 Jan-15 Feb-15

5-yr range 5-yr avg 13-14 14-15

Winter 2014-15 Outlook: End-Mar Inventories Set to Double 2014 Levels, But Mostly Priced In A storage surplus by end-March should keep winter prices under pressure. Under normal winter conditions, our analysis shows that inventories will end March 2015 at 1.73 Tcf versus 857 bcf in Mar 2014 and a 5-year average level of 1.64 Tcf. In a bear case where mild conditions persist, end-Mar exceeds 2 Tcf, likely leading prices to retest 2012 lows during Apr/May.

Mild weather and supply growth have more than offset lower starting inventories. We long argued that 3.4-3.5 Tcf in storage would be more than sufficient for winter 14-15 given the pace of injections and upcoming supply growth. Mild weather in Dec and another surge in NE production have more than offset the inventory concerns, causing withdrawals to fall well below prior year levels, even during most cold snaps. Even with freeze offs, supply is now running ~5 Bcf/d higher YoY.

Weather still matters near-term, creating upside risk from current levels. A surprise return of the Polar Vortex in late November, and subsequent rally to $4.50/MMbtu has been followed by milder conditions in December and a sell-off back below $3/MMbtu. A turn colder could add to volatility and upside near term, particularly with positioning historically short. A colder Jan-March could also lift the amount of injection required during the summer and take some pressure off prices. That said, there is no scenario where end-Mar inventories won’t be significantly higher YoY, and the longer mild conditions persist, the more challenged our bull case becomes.

Source: EIA, Bloomberg, Morgan Stanley Commodity Research estimates

Inventories Are Set To End-Mar At Nearly 2X 2014 Levels (Oct-March storage inventories and March 2015 forecasts, Bcf)

Supply Growth Has More Than Made Up For Lower Starting Storage (US dry gas production 2015 vs 2014, bcf/d)

Source: Bentek Energy, Morgan Stanley Commodity Research estimates


34


-0.8 -0.8 -1.0 2.62.3

2.8 0.1

Production YoY NeededCTG

Less StorageDemand Res/Comm Mex/CAD/LNG

Industrial &Misc Demand MATS Impact

5.4

3.6

2.3

0.0

1.0

2.0

3.0

4.0

5.0

6.0

$2.50 $3.00 $3.50 $4.00

With MATS Beyond MATS

2015 Injection Season Outlook: Power Markets Must Come To the Rescue Again, But Price Elasticity Is Falling Much higher inventories necessitate a smaller YoY injection. Starting from an end-Mar level of 1.73 Tcf, S&D balances during summer 2015 need to be tighter by ~3 Bcf/d YoY to correct for outsized injections seen during summer 2014 and keep inventories below physical storage limitations by end-Oct.

Supply growth should slow, but remains a significant headwind. Production should conservatively add 2.3 Bcf/d YoY to market supply during the summer months.

Demand and coal retirements help, but material CTG switching still required. Lower Canadian imports, higher Mexican exports, higher industrial demand and coal retirements will help tighten balances during the injection season, but they are insufficient to meet the challenge. Even with this help, coal-to-gas switching >2 Bcf/d (beyond MATS coal retirements) is needed in the summer to keep inventories at 3.82 Tcf by end-Oct 2015.

Picking up incremental gas power demand is becoming more difficult. Weak NE gas prices, coal retirements and lower coal prices have reduced power demand elasticity and have lowered the price point required to stimulate sufficient switching versus historical measures. The industry will need to look toward the SE power grid, which is a blended coal market, to incentivize gas power demand to balance in 2015.

Based on our balances, a price averaging closer to $2.95/mmBtu over the injection season should be sufficient to drive enough uptick in demand. However, if history is any guide, prices are likely to be even lower in the Apr/May and may quickly stimulate enough demand to help prices recover modesly in 2H15.

Source: EIA, Bloomberg, Morgan Stanley Commodity Research estimates

Summer 15 Price Elasticity to Power Demand/Switching (x-axis: 2015 Henry Hub, $/mmBtu; y-axis: YoY ∆ in summer 2015 US gas power demand with/without MATS coal retirements, bcf/d)

Little Demand Help in 2015 While Supply Growth Is Likely to continue (YoY change in summer natural gas balance: 2015 base case vs. 2014, bcf/d)

Source: EIA, HPDI, NOAA, Morgan Stanley Commodity Research estimates


35


$2.90 $2.75

$3.15 $3.35

$2.35 $2.25 $2.50

$2.75

$3.85 $3.75 $4.00

$4.25

$2.00

$2.50

$3.00

$3.50

$4.00

$4.50

$5.00

$5.50

$6.00

1Q13

2Q13

3Q13

4Q13

1Q14

2Q14

3Q14

4Q14

e

1Q15

e

2Q15

e

3Q15

e

4Q15

e

Lege

nd

Base

Fwd Curve

Bear

Bull

$1.50

$2.50

$3.50

$4.50

$5.50

$6.50


5-yr range 2012 2013 2014 2015 5-yr avg

2015 Quarter by Quarter Outlook – Price Weakness Most Extreme in the Summer Gas prices for 2015 are expected to remain at a significant discount to 2014 levels, and should prove weakest during the summer months when coal-gas switching becomes most relevant. We revise our base-case forecast lower by $0.50/MMbtu to $3.00 and introduce quarterly forecasts here:

• 1Q ($2.90 base case): A path to end-Mar storage of 1.7 Tcf will likely keeping prices under $3. Under normal weather, residential/commercial and industrial demand should be lower. YoY production growth in excess of 4 Bcf/d for most of the quarter also lends to lighter storage demand.

• 2Q ($2.75 base case): With a 700+ Bcf YoY storage surplus to start the summer injection season, prices will need to price to incentivize ~2.6 Bcf/d of coal-to-gas switching over the summer, in excess of the 1 Bcf/d impact from MATS, which begins in April. Prices tend to overcorrect early in the season and may stimulate enough demand in 2Q to help prices recover in 2H15. If weather is mild too, prices could revisit 2012 lows in April.

• 3Q ($3.15 base case): Injections during summer 2015 should average just 9.9 Bcf/d, compared to 2014 records of 13 Bcf/d. However, prices should rise from 2Q levels as the market finds more comfort with the end-Oct storage outlook as 2Q weakness helps tighten balances. Also, an extremely mild 3Q14 means YoY weather comps could prove more difficult during peak summer demand days.

• 4Q ($3.35 base case): Prices remain subdued into 4Q15 despite the start-up of train 1 (0.14 Bcf/d) of Sabine Pass. 1) Inventories are expected to return to normal 3.7-3.8 levels. 2) Supply is likely to see another boost with ~3 Bcf/d of pipelines added in 4Q15 within the Marcellus/Utica.

Fundamental Weakness, But Mostly in the Price (MoM change in natural gas storage: 2015 base case vs. 2014, bcf/d)

Source: EIA, Morgan Stanley Commodity Research Estimates Source: CME Morgan Stanley Commodity Research

Prices Typically Overcompensate Early in the Injection Season (Monthly average power demand , Bcf/d)


36


Supply Outlook


37


-

2,000

4,000

6,000

8,000

10,000

12,000

14,000

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

Northeast Premium MidAtlantic/South MidCon/Canada

2015 Production Outlook – Another Year of Impressive Growth

Marcellus/Utica Drive Growth in 2015 Offsetting Conventional Declines , Less Associated Gas

NE Infrastructure Capacity Increases 4.2 Bcf/d from 1H15 to 2H15, Starting With Rex Reversal (NE pipeline additions by end market, MMcf/d)

Record production growth driven by Northeast US basins, will continue to be a major headwind for gas balances in 2015.

Marcellus dominates US shale production in terms of well performance and today is the most productive US gas basin. Pipeline flows indicate current NE production at ~19 Bcf/d or ~26% of total dry gas production. We forecast NE supply growth (Marcellus + Utica) of 3.2 Bcf/d in 2015 (esp with less freeze-offs), compared to total US dry production growth of 2.7 Bcf/d YoY.

Growth is weighted toward the winter months given new infrastructure timing. New pipelines are likely to nearly fill by the end of 1Q15, constraining further growth until the 1.2 Bcf/d REX East-to-West reversal goes into service in 2Q15 (though this won’t add an incremental outlet until 3Q15). In 4Q15, another 3 Bcf/d of capacity is planned to go in-service that should fuel growth through year-end 2015.

Associated gas production is expected to add 1.8 Bcf/d to gas supplies in 2015. While ~0.3 Bcf/d lower than our original forecasts, the impact from slower-oil directed drilling is weighted toward 2H15 just as NE supply ramps.

Slowing declines at higher-cost shale plays, NE production mitigate the impact of slower associated gas growth. For example, Barnett/Haynesville, which combined for ~2 Bcf/d of declines in 2014, should fall less than 1 Bcf/d in 2015 as existing wells continue to age.

Source: Bentek Energy, Morgan Stanley Commodity Research Source: HPDI, EIA, Morgan Stanley Commodity Research estimates

(Build up of YoY change in US gas production by type, quarterly in Bcf/d

-6

-4

-2

0

2

4

6

8

10

1Q14

2Q14

3Q14

4Q14

1Q15

2Q15

3Q15

4Q15

Barnett Fayette + Woodford HaynesvilleMarcellus Eagle Ford Utica + WVOther Shale Associated Conv/GOM/CBMYoY Dry Gas

MS Forecast


38


1.0%

1.5%

2.0%

2.5%

3.0%

3.5%

4.0%

2000

2001

2002

2003

2004

2005

2006

2007

2008

2009

2010

2011

2012

2013

0

10

20

30

40

50

60

70

80

90

0%

10%

20%

30%

40%

50%

2006 2007 2008 2009 2010 2011 2012 2013 2014 2015

Gross L48 Gas Prod (RHS) % Shale % Assoc

Forecast

Associated Gas Growth May Slow, But Not As Helpful As Expected

Associated Gas Will Remain A Key Supply Source in 2015

Source: EIA, HPDI, Morgan Stanley Commodity Research estimates

(LHS:% of total gross gas supply, RHS: L48 gross gas production, bcf/d))

A Fair Amount of Gas Production Never Makes it To Market (% of gross gas production that is vented, flared or used for repressuring)

Source: EIA, Morgan Stanley Commodities Research

Associated gas production should still contribute significantly to production growth in 2015. While the recent decline in oil prices has created concern about associated gas growth, a number of offsets should continue to support associated growth in the 2 Bcf/d range in 2015. • Low breakevens in the Eagle Ford and Permian (50% of associated gas production) likely shields some of the growth. • A sizeable amount of associated gas doesn’t reach the market today. According to EIA, 20% of L48 associated gas production was reinjected

(mostly in TX) in 2013, while ~11% was flared (mainly in TX&ND), limiting the market impact if these volumes are lost. • Oil producer inertia may limit the magnitude of oil slowdown near term. Factors such as well backlogs, pad drilling, producer hedging, covenant

obligations, midstream agreements and rig contracts could also support production beyond what the market expects. Capital efficiency and high-grading of the portfolio can also offset the reductions in capex, similar to natural gas during 2012.

A pullback in oil can also have bearish implications for natural gas both in the near and long term. • Canadian gas demand at risk. This is a key outlet for rising Canadian production which may otherwise come into the US. With higher cost Canadian oil

sands projects out of the money, feedstock gas demand likely won’t grow. If $35-$40/bbl cash costs are sustained, existing demand of 1.9 bcf/d is at risk. • Ethane rejection could rise. Lower oil prices have pressured the NGL basket lower, causing ethane frac spread margins to turn dangerously negative.

In a similar episode in 2013, we saw ~30 kb/d of ethane rejection, which boosted gas supply by 150-300 MMcf/d. • Long term demand growth partly depends on high oil: Longer term demand projects (LNG/Industrial) are highly dependent on high oil/gas price

ratios and may delay FID until economics improve.


39


Demand Outlook


40


10

15

20

25

30

35

40


Range Avg 2015 2014 2013

Power Demand Must Increase During Apr-Oct To Slow Injections

Summer Builds Must Come In Well Below 2014’s Record Pace (MoM change in natural gas storage: 2015 base case vs. 2014, bcf/d)

Source: EIA, Morgan Stanley Commodity Research estimates Source: EIA, NOAA, Morgan Stanley Commodity Research estimates

Weather Comps, CTG Switching, MATS Should Elevate Gas Power Demand (Monthly average power demand , Bcf/d)

Power demand will once again be the balancing item in the market. With few other sources of new demand and limited price elasticity, gas power demand will once again be the driving force behind pricing this summer. Higher gas power demand (lower prices) will be required during the summer to slow injections. The gas market injected 2.7 Tcf during Apr-Oct 2014 vs. a 5Y average of 2.0 Tcf. 2015 injections will need to slow to a more modest 2.1 Tcf to keep storage at reasonable levels for end-Oct 2015. Considering few other demand sources and additional supply growth, total gas power demand may need to rise 3.6 Bcf/d YoY during the injection season. Coal retirements are helpful, but insufficient. ~12 GW of coal-fired generation is set to retire in 2015 with the new mercury standards (effective Apr 2015). However, we see ~1 Bcf/d of impact as low gas prices and poor utilization have curtailed the use of many of these plants already. Lower prices will be needed once again to stimulate gas power demand. MATS and normal weather should boost gas demand YoY, but we see the need for >2 Bcf/d of incremental power demand beyond these measures. Such an increase is likely only if prices average $3.0 or lower during the summer.

050

100150200250300350400450500

Apr May Jun Jul Aug Sep Oct

09-13 Range Avg 2015 2014


41


23%

27%29%

32%

38%

35%36%

42%

36%37%

35%

29% 28% 28%

0

500

1000

1500

2000

2500

3000

3500

4000

4500

15%

20%

25%

30%

35%

40%

45%

2008 2009 2010 2011 2012 2013 2014

Summer CDDs NE/MAT/SAT Gas NE/MAT/SAT Coal

0%

10%

20%

30%

40%

50%

60%

70%

80%

90%

Jan-06 Mar-07 May-08 Jul-09 Sep-10 Nov-11 Jan-13 Mar-14

Total Coal Gen Total Gas Gen

0

2,000

4,000

6,000

8,000

10,000

12,000

14,000

2013 2014 2015 2016 2017 2018 2019 2020

East MW SERC MW West MW

MATS Retirements Help, But Cannot Balance Supply Alone

Eastern Based Coal Retirements May Have Limited Impact With Already Cheap NE Gas

Source: EIA, Morgan Stanley Commodity Research Note: NEW= New England, MAT= MidAtlantic, SAT = South Atlantic

Despite Mild Summer Temps, NE Gas Burn Increased as Coal Stayed Flat

(MW of Coal Capacity)

Regional gas dynamics seen reducing the uplift from coal retirements. MATS should add only 0.3 Bcf/d to NE gas power demand and just 1 Bcf/d beginning in April to total 2015 power demand, given lower NE gas prices and poor utilization.

Coal retirements are PJM heavy. ~12 GW of installed coal capacity is expected to retire in 2015, needing to meet an April 1, 2015 MATS compliance date. 67% of those retirements take place in PJM, which now realizes the cheapest prices for natural gas in the US. An equal and smaller share of retirements, ~2 GW, is due to retire in SERC and the West.

Falling coal fleet utilizations are also a major issue. Coal plant utilization rates across the entire US have fallen >10% over the last 11 years, meaning that even the existing coal units are running less often thanks to competition from gas and renewable sources. In addition, to-be retired plants are typically de-rated ahead of retirement, therefore making gas demand uplift less meaningful.

Source: EIA, Morgan Stanley Commodity Research

Falling Coal Utilization Rates Reduce Gas Demand Uplift from Retirements (% of installed capacity utilized and 12 mo moving average)

Source: SNL, Morgan Stanley Commodity Research estimates Note: East includes Midwest and Midatlantic, SERC includes Bituminous

(LHS: NEW/MAT/SAT % summer load met by coal and gas, RHS: NEW/MAT/SAT summer CDDs) April 2015 MATS

Compliance Date


42


$(2.00)

$(1.00)

$-

$1.00

$2.00

$3.00

$4.00

Jan-12 Jul-12 Jan-13 Jul-13 Jan-14 Jul-14

Tetco M3 Chicago Tetco M2

PRBPRB

PRB

PRB

PRB

PRB

NAPPNAPP

CAPP

CAPP

ILB

ILB

ILB

W. Bit.

W. Bit.

Other

OtherOther Other Other

Other

0%

10%

20%

30%

40%

50%

60%

70%

80%

90%

100%

ERCOT MISO PJM SERC SPP WECCPRB NAPP CAPP ILB W. Bit. Other

18,162

11,6509,926

8,346

3,766 3,340 2,855

136$2.25

$3.00

$3.75

$4.50

0

4,000

8,000

12,000

16,000

20,000

Tetc

o M

3

Tetc

o M

2

Chi

cago

Tran

sco

Z5

Tran

sco

Z6

Dom

inio

n

TCO

Leid

y/Z4

Hen

ry H

ub

MW Summer 2013 Summer 2014

Lower Coal/Gas Switching Elasticity May Keep Prices In a Lower Range

Higher Cost CAPP/NAPP Coals Priced Out of PJM Market in 2014

Source:SNL, Morgan Stanley Commodity Research

Prices Have Been Low At Key PJM Gas Generation Hubs, Limiting Switching Options (LHS: MW of Gas Capacity, RHS: Summer average gas price, $/MMbtu )

Incentivizing gas power demand is becoming more difficult. Gas may need to price even lower than historically seen to produce the same demand impact. Key factors include: 1. Already low gas prices in the NE/PJM markets. PJM was a traditional

source of coal-to-gas switching. However, TETCO M3 saw sub-$3 prices during most of summer 2014 making it difficult to achieve incremental coal-to-gas switching within PJM. This will put more emphasis on SERC, or incremental demand from TETCO M2 and Chicago Citygate hubs.

2. Lower coal prices likely in 2015. Bearish demand projections for coal have weighed on prices, while increased blending with lower cost ILB and high PRB coal burn in SERC have reduced delivered costs. Lower coal prices means gas has to fall that much further to stimulate the same gas demand response.

3. Oil price weakness reduces coal transport costs. Transport costs for coal can account for 10-15+% of the delivered cost and are a key input in the coal/gas switching equation. Lower oil prices have a more dramatic impact on PRB delivered coal given longer transport routes relative to other coal types.

Source: CME, Morgan Stanley Commodity Research

Lower M3 Prices Already Supporting Gas Power Burn (Gas price vs Henry Hub, $/MMBtu)

Source: Bloomberg, SNL, Morgan Stanley Commodity Research estimates

(Coal consumption by coal type)


43


14

15

16

17

18

19

20

21

22

23

24


5-yr range 5-yr avg 2015 2014 2013

Industrial Demand Sees Small Gains Until 2016+

Industrial Demand Declines During Winter, But Gain Marginally Throughout 2015

Source: Bentek Energy, Morgan Stanley Commodity Research

Petroleum-Based (Methanol, GTL, etc.) Industrial Projects Driven by High Oil/Gas Ratios

(Planned Industrial Demand by type by year, MMcf/d)

US industrial gas demand is showing small signs of structural growth. Industrial demand has been one secular bright spot in the gas market in recent years. In 2014, YTD industrial demand has grown by ~1 Bcf/d. Growth should be challenged in winter, but new plant completions in late 2014/2015 should lift industrial demand 300 MMcf/d for full-year 2015. Notable completions include:

• 2014 (expected) completions: Southeast: Geismar,LA Methanol Plant (~90 MMcf/d) in 4Q , Rockies: Keota LNG Plant (30 MMcf/d) in 4Q14/1Q15

• 2015 (expected) completions: Midcontinent: DRI Plant by Essar Steel Group (217 MMf/d) in 4Q15, Iowa Fertilizer Ammonia Plant (152 MMcf/d) in 4Q15 and Texas: Calanese Methanol Plant (117 MMcf/d) in 3Q15

However, normalizing weather in 2015 should keep growth capped. Much of the growth in industrial demand in 2014 was due to extreme 13/14 winter demand. Adjusting for the weather impact in 2015, winter industrial demand will fall short of 2014. Long term demand prospects are robust, but could prove optimistic. Planned industrial-based capacity is ~5 Bcf/d through 2020, but many of these projects are uncertain. A large percentage of new industrial demand comes from GTL plants in the Southeast (Sasol’s GTL plant in Westlake LA is worth ~1 Bcf/d in 4Q20), which are highly levered to oil/gas ratios remaining elevated. While projects already under construction may proceed, those awaiting FID may be delayed given recent declines in oil prices that hurt project economics.

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

(Industrial natural gas demand, Bcf/d)

0

200

400

600

800

1000

1200

1400

2014 2015 2016 2017 2018 2019 2020

Chemicals Industrial Machinery Metals Petroleum Primary Metals


44


0

100

200

300

400

500

600


5-yr Range 2014 2015 5-yr Avg

-1

0

1

2

3

4

5

02468

101214161820

Jan-

10A

pr-1

0Ju

l-10

Oct

-10

Jan-

11A

pr-1

1Ju

l-11

Oct

-11

Jan-

12A

pr-1

2Ju

l-12

Oct

-12

Jan-

13A

pr-1

3Ju

l-13

Oct

-13

Jan-

14A

pr-1

4Ju

l-14

Oct

-14

NE Prod West MidWest Northeast

Canadian Imports Set to Fall

Lower Canadian Storage May Limit US Exports


Canada Exports to MW/West Held Strong; NE Exports Have Reversed (LHS: NE Gas Production, Bcf/d, RHS: Canadian Imports by US region, Bcf/d)

Normalizing weather and continued NE production growth is expected to send Canadian imports lower in 2015. • Canadian imports increased ~1 Bcf/d YoY last winter thanks to record cold in the Midwest and Northeast. 2014 FY imports are still expected

to show a slight decline as summer demand disappointed, Canadian storage demand was high and Northeast-to-Canada summer exports increased • Assuming normal winter weather, US Canadian gas imports should fall another 0.3 Bcf/d in 2015. Key contributors include normal weather and

increased competition from Northeast gas supply as it begins competing in the Midcontinent in 2H15.

Low inventories in Western Canada only reinforce the potential for lower exports. • While US and NE storage refilled to adequate levels prior to winter, Western Canadian storage was less successful. Western Canadian gas

storage remains 40 Bcf lower YoY. If weather leads to a stronger local demand pull on storage, export arbs to the US are likely to come under pressure and keep more gas in Canada.

Source: Bloomberg, Enerdata, Morgan Stanley Commodity Research estimates

(Western Canada gas storage, Bcf)


45


0

2,000

4,000

6,000

8,000

10,000

12,000

2013 2014 2015 2016 2017 2018 2019 2020

Transport Services Residential

Industrial Petroleum Electricity

0

0.5

1

1.5

2

2.5

3


5-yr range 2014 2015 5-yr avg

US Net Imports Falling; Mexican Exports Increasing With New Infrastructure

Mexican Demand Expected to Grow, But Slowly

US L48 net imports are falling as exports increase and growing US production displaces imports. • Canadian imports have fallen with NE production, but Mexico and LNG are new and growing export options.

Mexican border crossing expansions increasing, but will it translate to increased volumes? • In 4Q14, the Net Midstream/Pemex Agual Dulce- Fontera project added 2.1 Bcf/d to export capacity, sending total export capacity to ~9.6 Bcf/d

Exports have been slow to fill, but we think they ultimately grow 0.5 Bcf/d in 2015. • Key Mexican expansions don’t occur until mid 2015+, so the ramp up may be more delayed. • Infrastructure bottlenecks within Mexico have also limited the opportunity thus far.

Mexico remains a key source of potential demand growth. • A healthy industrial economy, existing supply chains, and a reliance on expensive imports all make Mexico a material outlet for US natural gas in the

future, once adequate infrastructure is in place. • 15 GW of simple/combined cycle plants due to be added within Mexico through 2025. • The key risk is if Mexico is successful in lifting domestic production under petroleum reform measures


Mexican Exports Modestly Growing in 14&15 (US Pipeline Exports to Mexico, Bcf/d)

Source: SENER, Morgan Stanley Commodity Research estimates

(Annual average demand by sector, Mmcf/d)


46


US LNG Exports Commence in 2015, But Remain Small Until 2017+

The First LNG Exports Should Come As Soon As Early as 4Q 2015

LNG Export Pipeline Is Much Larger Than What Can Be Realized

Cheniere’s Sabine Pass Train 1 is estimated to be operational in 4Q15. The first train has a capacity of 0.55 Bcf/d but will only be operational for 4Q15 despite construction progress that has been ahead of schedule (76% complete as of 9/30/14), placing annual average exports at just 0.14 Bcf/d in 2015. Cheniere expects trains 2-4 to come on-line on a 6-9 month staggered basis, making likely delivery from additional trains in 2Q16, 4Q16, 2Q17 and 4Q17 with cumulative capacity of 2.8 Bcf/d. FID for trains 5-6 are expected to come in early 2015 with first LNG by 2018 and would add an additional 1.38 Bcf/d in export capacity.

FERC approvals may be the more critical thing to watch in 2015. Given the new standards for approving LNG export licenses, achieving FERC approvals will be the most time consuming and expensive process new facilities go through. The large scope and size of LNG export facilities, and the fact that many are located within densely populated areas, increases the likelihood of FERC delays. Constraints on engineering and labor, along with shrinking economics could also cause demand to slip.

We maintain our forecasts for ~10 Bcf/d of US LNG exports by 2020. 5-6 major US LNG export projects are likely to be built – mostly fee-based brownfield projects. Challenges to upsizing are likely growing, specifically engineering, labor and financing resources, permitting and global competition (e.g. ANZ, Mozambique, Israel) later in the decade. Spiraling oil prices also hinder project economics, potentially delaying projects undergoing FID.

Source: Company data, FERC, DOE, Morgan Stanley Commodity Research

(LNG export applications, Bcf/d) (Estimated average LNG export volume by year, bcf/d)

Source: DOE, Company Data, Morgan Stanley Commodity Research estimates

-

2.00

4.00

6.00

8.00

10.00

12.00

2015 2016 2017 2018 2019 2020

Sabine Pass Freeport Cameron

Cove Point Lake Charles Elba Island

5.7 4.8

27.5

0.0

5.0

10.0

15.0

20.0

25.0

30.0

Full Non- FTA Authorization Conditional non FTAAuthorization

Under DOE Review

Sabine Pass, Carib Energy, Cameron LNG, Freeport LNG, Freeport Exp

Lake Charles, Cove Point, Jordan Cove, Oregon LNG


47


28%

75%

37%

0%

10%

20%

30%

40%

50%

60%

70%

80%

90%

100%

2013 2014 2015

Positioning to Play A Role in 2015: Lightly Hedged Producers May Look to Act On High Prices While The Spec Community Remains Historically Short

2015 Producer Hedging Down YoY (as of 3Q14) (% of gas production hedged for SMID Cap Universe at end of 3Q14 – not reflective of entire industry)

Source: Company Data, Morgan Stanley Commodities Research

Short spec positioning could support more volatility in late Jan-Mar. Heading into the Nov rally, CFTC managed money positioned had been the shortest since Apr-2012. However, a wave of short covering followed the early cold snap in Nov. Shorts have since increased as Dec weather has proven mild, which may lend to a bearish bias for trading this winter, but also introduces the potential for heightened volatility if weather surprisingly turns cold in 2H of winter.

Producer hedging also limits upside opportunities. Despite early summer optimism, the 2015 strip has failed to rise above the $4/MMbtu mark for any length of time since July, thus providing limited opportunity for hedging from gas producers. The latest CFTC data shows that the producers, merchants and processors group held 391K in net length as of Dec 30 which is the longest the group has been positioned. Not only are producers lightly hedged, but low prices ahead of peak winter months have provided opportunities for utilities to hedge winter gas consumption at sub $4 vs. $10+ realized prices in winter 2013-2014.

$0.00

$1.00

$2.00

$3.00

$4.00

$5.00

$6.00

$7.00-200,000

0

200,000

400,000

600,000

Jan-10 Aug-10 Mar-11 Sep-11 Apr-12 Nov-12 Jun-13 Jan-14 Aug-14

NYMEX PMP Net ICE HH OTC PMP NetNYMEX Swap PMP Net NYMEX HH Pen Swap PMP NetNYMEX Euro Style Opt PMP Net HH Last Day Fin PMP NetICE Pen PMP Net TotalGeneric 12 month strip (rhs)

Producers May Have Opportunity to Hedge for 2015 (LHS: Disaggregated CFTC data for PMP net position, # of contracts, RHS: reverse generic 12 month NYMEX contract, $/MMbtu)

Source: CFTC, ICE, CME, Morgan Stanley Commodities Research

$2.75

$3.00

$3.25

$3.50

$3.75

$4.00

$4.25

$4.50

$4.75

$5.00

$5.25

-200,000

0

200,000

400,000

600,000

800,000

1,000,000

Jan-13 Apr-13 Jul-13 Nov-13 Feb-14 Jun-14 Sep-14 Jan-15

NYMEX MMNet ICE HH OTC MM NetNYMEX Swap MM Net NYMEX HH Pen Swap MM NetNYMEX Euro Style Opt MM Net HH Last Day Fin MM NetICE Pen MMNet TotalGeneric 12 mo stip (rhs)

While Managed Money Positioning Remains Bearish (LHS: Disaggregated CFTC data for Managed Money net position, # of contracts, RHS: generic 12 month NYMEX contract, $/MMbtu)

Source: CFTC, ICE, CME, Morgan Stanley Commodities Research


48


Northeast Gas Outlook


49


NE Balance 2013 2014 Base Bear Bull Base Bear BullRes/Com 8.9 9.9 9.3 7.9 10.4 (0.6) (2.0) 0.5 Industrial 4.5 5.1 4.8 4.5 4.9 (0.3) (0.6) (0.2) Other 0.5 0.5 0.6 0.6 0.6 0.1 0.1 0.1 Demand before Power 13.9 15.6 14.7 13.1 16.0 (0.8) (2.5) 0.4

Production 13.8 18.0 22.0 22.1 21.7 4.0 4.1 3.7

Pipeline Imports 5.3 3.3 2.3 3.0 3.0 (1.0) (0.3) (0.3) Effective Intra-NE Pipe Adds 2.3 4.3 5.3 4.6 4.6 1.0 0.3 0.3

Exports 2.3 2.6 3.6 3.2 4.9 1.0 0.6 2.3 Effective Export Pipe Adds - 0.5 1.5 1.1 2.8 1.0 0.6 2.3

Net Imports 3.0 0.7 (1.3) (0.2) (1.9) (2.0) (0.9) (2.6) Total Supply 16.8 18.7 20.7 21.9 19.8 2.0 3.2 1.1

YoY ∆ in Storage - bcf/d (0.6) (0.6) 0.3 0.3 0.3 0.9 0.9 0.9 Power Burn 3.5 3.6 5.6 8.5 3.5 1.9 4.9 (0.2) Weather Benefit vs. 10Y Norm 1.1 1.3 - (2.0) 1.3 (1.3) (3.3) 0.0 Normalized Power Burn Req 4.6 4.9 5.6 6.5 4.8 0.7 1.6 (0.1)

2015 2015 YoYAbsolute

$-

$1.00

$2.00

$3.00

$4.00

$5.00

$6.00

$7.00

Apr-14 Oct-14 Apr-15 Oct-15

Tetco M3 Chicago HH ZN 6 NNY

Forwards

Northeast Basis: More Deterioration Likely Into 2015

Source: CME, Bentek, Morgan Stanley Commodity Research

Without the Benefit of Extreme Weather, PJM Balances Face More Pressure (NE supply/demand balances, Bcf/d)


(Spot gas prices at NE gas hubs and HH, $/MMbtu)

More Room for Local Prices to Fall In 2015

Note: NE Balances include Maine, New Hampshire, Vermont, Massachusetts, Rhode Island, Connecticut, New York, New Jersey, Pennsylvania, Delaware, Maryland, Virginia, West Virginia, Ohio and Kentucky

Northeast prices have already shown weakness in 2013/2014, but further pain is likely ahead. Supply growth continues to be the major headwind for NE gas markets which is expected to continue in 2015 thanks to further expansion of midstream capacity. While 2014 had a record cold winter and historically low inventories to support prices (particularly in 1H14), 2015 is shaping out to be much more mild and has led to storage surpluses in the NE.

NE balances are running out of levers to pull. Coal/gas switching remains the largest of all levers and can still swing largely, but requires prices even weaker than 2014 depressed levels. With weakness already felt at a number of Appalachian hubs (particularly M3) weakness may need to spread further east to incentivize increased power burn to help balance. In addition, the majority of imports have now turned to exports leaving minimal available volumes to displace with new export lines. This may compound the issue of needed local burn coal/gas switching as more volumes may be constrained.

Longer term balance depends on export optionality and SE demand growth. ~30 Bcf/d of dedicated NE export lines are anticipated to commence before 2019. Nearly half of that will target the SE/USGC region when demand growth is centered (LNG exports, industrial, power demand). The key to returning the NE to sustainable price levels will be completed needed midstream capacity. That said, variance in tariff rates and end-market locations leaves uncertainty into which projects will go forward. Longer term basis is estimated to revert to future tariff rates in the range of $0.80-$1.00/MMbtu.

.


50


524

667703 732

689732

484

652

787

$-

$2.00

$4.00

$6.00

$8.00

$10.00

$12.00

0

100

200

300

400

500

600

700

800

900

2006 2007 2008 2009 2010 2011 2012 2013 2014

Summer Inj M3 Avg M2 Avg

0

200

400

600

800

1000

1200


5-yr range 5 yr avg 2013 2014

Northeast Basis: Record Injection In 2014 Despite Low Prices Is Worrisome NE inventories recovered quickly in summer 2014 despite extremely low levels to start the season. Northeast gas inventories recovered quickly over the summer, injecting a record 787 Bcf from April-Oct. This record pace was achieved despite extremely low local gas prices in the summer. If not for these prices, which lifted power demand, injections would have been even higher.

NE inventories have likely moved into surplus reducing the need for injections in 2015. Consuming East inventories have moved into a YoY surplus back in December, despite starting with a 352 bcf deficit in Apr 2014. The record pace of injections from 2014 will need to slow – we believe closer to 685 bcf in 2015 to keep end-Oct storage at 5Y averages. The problem is that with winter 2015 likely falling short of 2014 extremes and supply growing, keeping injections below 2014 levels is becoming increasingly difficult.

Is there a risk of hitting full storage in the East? NE working storage capacity is 1.82 Tcf while Inventories reached 977 Bcf in Oct 2014. With injections expected to run at a blistering pace and more supply coming this summer, regional storage could reach full levels without new outlets for regional gas.

New outlets are coming, but local demand likely needs to increase as well – that requires even lower prices. With the ability to displace imports significantly decreasing and export options still limited relative to supply growth, NE balances will need to consume more gas regionally to balance. Power demand can still be stimulated, but elasticity is fading with prices already so low.


NE Inventories Are Higher YoY Despite Record Draws in Winter 13-14 (Seasonal NE gas storage levels, Bcf)


(lhs: summer injection, Bcf ; rhs: summer average cash price, $/MMbtu))

Record NE Injections Will Need to Unwind, But Will Be Hindered By Already Low Prices and Supply Growth

Physical NE Storage Capacity


51


0.0

0.5

1.0

1.5

2.0

2.5

3.0

3.5

4.0

4.5

5.0

Jan-13 Jun-13 Nov-13 Apr-14 Sep-14 Feb-15 Jul-15 Dec-15

SW PA NE PA WV Utica

Northeast Basis: Supply Marches On, But Shifting to the West/SW 2015 will be another big year for NE production growth. New infrastructure will continue to support production growth in the NE. We see total NE supply growth (Marcellus + Utica) of 3.2 Bcf/d for the balance of 2015. However, the NE gas supply/demand balance will face a larger 3.5 bcf/d of supply growth over the summer months, fueled by significant additions (totaling 2 bcf/d) in 4Q14 and 2Q15.

More of the production growth will shift to SW PA and Utica. With NE PA still highly constrained on infrastructure and awaiting the Constitution pipeline for relief, more of the activity and infrastructure investment has shifted towards the SW Marcellus and the Utica. We expect SW PA to grow 1-2 Bcf/d and 1 Bcf/d for the Utica vs. <0.5 Bcf/d for NE PA. Much of the infrastructure we have seen come online in late 2014 or that will come online in 2015 is designed to support production in these faster growing regions. In fact, the mix of uncompleted wells in PA has shifted towards the SW region.

Falling wet gas economics are a risk, but we continue to see significant activity. Ethane prices – the largest piece of NGL production in the Marcellus – have proven more resilient than oil and C4+. Between new infrastructure, a healthy backlog of uncompleted wells, and low breakeven prices, we expect production to continue at a robust pace through much of 2015.


More NE Supply in 2015: But Shifting to SW PA and Utica (YoY northeast production by region, bcf/d)

Source: PA DEP, Morgan Stanley Commodity Research

High Marcellus Uncompleted Well Inventory Just Waiting on Infrastructure (number of uncompleted wells in the PA Marcellus by region)


52


Northeast Basis: New Infrastructure Helps, But Even Export Projects May Do Little to Relieve NE Congestion

Rapid Supply Response After Expansions Provide Limited Price Relief (US dry gas production, bcf/d)

Source: Bentek, Morgan Stanley Commodity Research

New pipelines tend to bring a surge in production. Infrastructure constraints, chokes and uncompleted wells all support rapid production growth when new pipelines come online. Nov 2013 saw >1 bcf/d of pipeline capacity added, which was filled in ~1 week without adding many new wells. Nov 2014 saw production spike 1.5 Bcf/d after expansions, mostly within SW PA/Utica. Similar dynamics are likely to play out with other key projects.

Few NE imports left to displace limits options. NE net imports have fallen from 10+ Bcf/d as recently as 2010 to an estimated 2 Bcf/d of net exports in 2015. In fact, the NE is at risk of being a net exporter even during winter, which could completely eliminate the NE winter basis premium. With the ability to displace imports significantly decreasing, NE balances will need to find alternative measures to balance.

Limited offtake in new markets, expensive midstream contracts can limit relief for netbacks. New export infrastructure can move trapped gas out of the Northeast, but only at a high price. Moreover, this new supply may simply overwhelm the new destination market. For example, many markets in the Midwest or Midcontinent do not have sufficient demand (outside of heating) to absorb excess gas, especially during summer. The end result can be lower prices for new destinations coupled with a large pipeline tariff = no improvement in realizations. These dynamics will likely play out most prominently in SW PA / Utica, where we see basis at risk.

.

61

63

65

67

69

71

73

75

Jan-

13

Mar

-13

May

-13

Jul-1

3

Sep-

13

Nov

-13

Jan-

14

Mar

-14

May

-14

Jul-1

4

Sep-

14

Nov

-14

Jan-

15

4Q13: 2 bcf/d of NE pipe

expansions commence

ANR Lebanon Lateral, Rex Seneca Lateral,

TGP backhaul projects add 1.1 Bcf/d in 2Q14

TGP Rose Lake, Rex Seneca Lateral Ph 2, TETCO Team 2014, TETCO Team South

(5)

-

5

10

15

20

25

2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015

InboundTotal Production Outflows NE DemandSource: CME, Bentek, Morgan Stanley Commodity Research

Higher Production, Lower Imports Limit Options for NE Gas

(left-axis: Northeast imports, production, and demand, mmcf/d; right-axis: TCO Appalachia Pool basis, $/mmBtu)


53


2

3

4

5

6

7

8

9

Jan-

15

Feb-

15

Mar

-15

Apr

-15

May

-15

Jun-

15

Jul-1

5

Aug

-15

Sep

-15

Oct

-15

Nov

-15

Dec

-15

5-yr range 5 yr avg 2013 2014 2012

360

1,045787

749 428

64 359

0200400600800

1,0001,2001,4001,6001,8002,000

End

Mar

ch 1

5

2014

inj

Prod

uctio

n

Net

Impo

rts

MAT

S

Req

'd P

ower

Bur

n

End

Oct

15

Northeast Basis: More PJM Power Demand Needed, Which Only Comes Through Lower Prices Few demand outlets to offset supply growth. 2014 injections averaged 3.85 Bcf/d in the NE – a pace that likely needs to slow to 3.2 Bcf/d to keep end-Oct inventories at 5Y averages. However, Production growth alone adds another 3.5 Bcf/d to the balance putting the YoY change in demand or net imports at 4.15 Bcf/d. Shifts in imports and exports can account for 2 Bcf/d and MATS is worth another 0.3 Bcf/d. That leaves power needing to increase 1.8 Bcf/d YoY in the NE to balance the market in our base case. NE power demand can rise to balance inventories, but only through lower local prices. PJM dispatch economics suggest an incremental 1.8 Bcf/d YoY this summer is possible, but it requires prices at $1.50/Mmbtu across Appalachia, with particular weakness in shoulder/summer months. Absolute price is more important than basis for dispatch economics. If Henry Hub is weaker, it does not necessarily translate into a 1-1 decrease in NE prices. In our base case, Dominion South and other supply-heavy hubs will remain the most discounted in terms of pricing in the $2.10-$2.30/Mmbtu range while TETCO M3 prices fall to $2.40-$2.60/MMbtu.

Source: EIA, Morgan Stanley Commodity Research

(YoY 2015 northeast summer balance waterfall, Bcf )

Even With Increased Exports, Higher Power Burn Required in 15 to Balance

Lower Prices in 2015 Should Again Boost NE Gas Burn (NE gas power demand, bcf/d)

Source: Bentek Energy, Morgan Stanley Commodity Research Note: NE Balances include Maine, New Hampshire, Vermont, Massachusetts, Rhode Island, Connecticut, New York, New Jersey, Pennsylvania, Delaware, Maryland, Virginia, West Virginia, Ohio and Kentucky


54


$(4.00)

$(2.00)

$-

$2.00

$4.00

$6.00

$8.00

$10.00

Jan-13 Apr-13 Jul-13 Oct-13 Jan-14 Apr-14 Jul-14 Oct-14

AECO Lebanon (OH) MichCon Tetco M3 Chicago

Northeast Basis: Basis Pain Is Likely To Spread

AECO Could Face More Pressure As Gas Continues to Leave the NE Market

Large demand centers could see the most incremental pricing pressure. Many NE production centers already face severe congestion, which may limit incremental downside. However, large demand centers like M3, Z6, M2 and Z5 could be forced lower to spur additional gas power demand. In fact, we argue this is a necessary condition, and this scenario becomes more likely as interconnectivity improves with new pipelines.

SW PA, OH could see more pressure as well. NE PA production centers are already near extreme lows during summer months, which has limited production growth. However, SW PA and Utica will be large sources of growth. Although new infrastructure is targeting these regions, it may prove insufficient. Moreover, even with new takeaway, high cost marginal transport (or end-market price deterioration) could weigh on these hubs.

MISO gas hubs at risk of falling in 2015. The REX East-to-West reversal in 2Q15 increases NE to Midcon export capacity to 1.8 Bcf/d. However, with limited interconnects from REX to Chicago, introducing cheap NE gas into Midcon markets may have negative impacts on regional basis.

Market share wars and displacement could weigh on AECO pricing as well. As NE production grows, we could see a continued displacement of imports from Canada. The NE is increasingly exporting to Eastern Canada or pushing back on imports flowing into the US. However, with more NE gas moving into the Midcon in 2015 (and ultimately Chicago), AECO will face a new battle against low cost gas supplies, particualrly during the summer. If Chicago and Midcon prices come under pressure, AECO may need to discount more to keep arbs to these regions open. Similarly, if oil prices fall enough to shut-in oilsands production, Western Canadian gas demand could be at risk as well.


MW Cash Prices Already Showing Less Response During Winter Extremes (basis prices (vs HH) for Midwest gas hubs, $/mmBtu)

$-

$1.00

$2.00

$3.00

$4.00

$5.00

$6.00

$7.00

$(2.50)

$(2.00)

$(1.50)

$(1.00)

$(0.50)

$-

Jan-13 Apr-13 Jul-13 Oct-13 Jan-14 Apr-14 Jul-14 Oct-14

MichCon Dawn Chicago NNG Ventura Henry Hub


(Aeco vs NE/MW gas hubs, $/mmBtu, rhs: Henry Hub, MMbtu)


55


Similar to Oil, Rising Production And New Infrastructure To Shift Gas Flow and Basis

Growing Marcellus Production Will Only Continue to Pressure Other Regions

Sour

ce: B

loom

berg

, EIA

, Mor

gan

Sta

nley

Com

mod

ity R

esea

rch

History shows new pipelines merely spread the pain. • New pipelines from NE PA in Nov 13 offered temporary relief to Z4 and other constrained hubs • However, prices simply fell in destination hubs and new production quickly pushed down Z4 prices even more.

As supply grows, displacing regional inflows will expand the pricing pressure to other supply hubs. • New NE pipelines will spread the pain around the region. • Backing out imports into the Northeast will leave more supply and price pressure in Canada, the Gulf, the Midwest and many other regions.

Northern hubs will move from a premium to a permanent discount as production and infrastructure grow • New supply and demand sources are in different geographic regions forcing infrastructure to realign. • Transport costs on these new pipelines will reset regional basis

Marcellusprod, bcf/d M3

DomSouth

TennZ4

TCOApp Z6 NY Lebanon M2 AECO

REX - Midwest

Jan-13 10.03 (0.89) (0.37) (0.13) (0.23) 2.41 (0.03) (0.39) 0.21 (0.00)Feb-13 10.35 (0.82) (0.23) (0.08) (0.16) 3.89 (0.03) (0.22) 0.12 (0.00)Mar-13 10.57 (0.10) (0.16) 0.05 (0.05) (0.44) 0.05 (0.16) (0.06) 0.13Apr-13 10.84 (0.14) (0.19) (0.20) (0.09) 0.20 (0.06) (0.24) (0.21) (0.01)May-13 11.34 (0.19) (0.21) 0.09 (0.08) (0.19) (0.06) (0.30) (0.05) (0.04)Jun-13 11.88 (0.29) (0.39) (0.32) (0.18) (0.27) (0.12) (0.38) 0.22 (0.00)Jul-13 12.32 (0.29) (0.52) 0.26 (0.17) 0.00 (0.03) (0.34) (0.25) 0.06Aug-13 12.70 (0.35) (0.44) (0.92) (0.17) (0.30) (0.02) (0.35) (0.50) (0.01)Sep-13 12.70 (0.23) (0.30) (1.89) (0.07) (0.11) (0.01) (0.28) (1.22) 0.01Oct-13 13.01 (0.35) (0.40) (1.74) (0.15) (0.29) 0.01 (0.39) (0.31) (0.00)Nov-13 13.97 (0.38) (0.58) (0.75) (0.23) (0.32) (0.11) (0.48) (0.27) (0.11)Dec-13 14.36 (0.52) (1.06) (0.97) (0.28) 0.02 (0.00) (0.77) (0.31) 0.14Jan-14 14.22 16.99 (0.52) (1.12) (0.19) 19.62 1.18 (0.37) (0.23) 1.16Feb-14 14.86 1.87 (0.39) (2.80) (0.13) 5.21 2.13 (0.04) 1.06 3.49Mar-14 15.16 0.67 (0.52) (1.75) (0.09) 2.08 0.27 (0.34) 0.12 0.68Apr-14 15.08 (0.68) (0.64) (0.77) (0.27) (0.71) (0.08) (0.68) 0.04 (0.03)May-14 15.64 (1.38) (1.35) (1.62) (0.39) (1.43) (0.13) (1.17) 0.12 (0.11)Jun-14 16.04 (1.52) (1.57) (1.46) (0.20) (1.54) (0.07) (1.36) 0.62 0.06Jul-14 16.61 (1.60) (1.68) (0.31) (0.22) (1.65) 0.01 (1.35) 0.45 0.02Aug-14 16.93 (1.74) (1.74) (1.49) (0.11) (1.73) (0.04) (1.49) 0.37 (0.06)Sep-14 17.18 (1.87) (1.83) (1.68) (0.21) (1.80) (0.07) (1.70) 0.14 (0.04)Oct-14 17.38 (1.95) (1.90) (1.79) (0.19) (1.67) (0.12) (1.89) (0.27) (0.14)Nov-14 17.92 (0.76) (1.04) (1.37) (0.46) (0.30) 0.15 (0.81) (0.49) 0.01Dec-14 19.32 (1.76) (1.51) (1.44) (0.46) (1.70) (0.09) (1.06) (0.35) (0.11)

vs. 5Y Median


56


A Number of Pipeline Projects Will Partially Alleviate the Gas-Short USGC Producers are looking to send Marcellus/Utica gas to the USGC. Realizing the Northeast will no longer need to import gas soon (except during very cold days), a number of pipeline projects between now and 2018 will ship gas from the northeast to the USGC, reversing the historical flow pattern.

Source: Companies data, Morgan Stanley Commodity Research

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

NE Marcellus to NortheastTransco NE Connector Project 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 TGP Rose Lake Expansion 230 230 230 230 230 230 230 230 230 230 230 230 230 230 230 230 230 TGP Niagara Expansion 158 158 158 158 158 158 158 158 158 158 158 158 158 Constitution Pipeline 650 650 650 650 650 650 650 650 650 650 650 650 AGT AIM 343 343 343 343 343 343 343 343 343 DTI Iroquois (NIMO East) 275 275 275 275 275 275 275 275 275 AGT Atlantic Bridge 150 150 150 150 150 TGP NED (NE Energy Direct Project) 2,200 Spectra Access Northeast 1,000 Total - - - 330 330 330 330 488 1,138 1,138 1,138 1,756 1,756 1,756 1,756 1,756 1,906 1,906 1,906 5,106

NE Marcellus to Mid-Atlantic/SouthTCO East Side Expansion 310 310 310 310 310 310 310 310 310 310 310 310 310 TRANSCO Leidy Southeast Project 525 525 525 525 525 525 525 525 525 525 525 525 525 Transco Atlantic Sunrise 1,700 1,700 1,700 1,700 1,700 1,700 PennEast Pipeline 1,000 1,000 1,000 1,000 1,000 Transco Diamond East 500 500 Total - - - - - - - 835 835 835 835 835 835 835 2,535 2,535 2,535 3,535 4,035 4,035

Wet Marcellus & Utica Takeaway projects to the MidCon and CanadaANR Lebanon Lateral 350 350 350 350 350 350 350 350 350 350 350 350 350 350 350 350 350 350 350 REX Seneca Lateral Phase 1 250 250 250 250 250 250 250 250 250 250 250 250 250 250 250 250 250 250 250 REX Seneca Lateral Phase 2 350 350 350 350 350 350 350 350 350 350 350 350 350 350 350 350 350 REX East-to-West 1,200 1,200 1,200 1,200 1,200 1,200 1,200 1,200 1,200 1,200 1,200 1,200 1,200 1,200 TETCO Uniontown to Gas City 425 425 425 425 425 425 425 425 425 425 425 425 425 ANR Glen Karn 133 133 133 133 133 133 133 133 133 133 133 133 133 ANR Lebanon Lateral (Phase 2) 350 350 350 350 350 350 350 350 350 Rover Pipeline Project 1,900 1,900 1,900 3,250 3,250 3,250 3,250 3,250 3,250 ANR East 2,000 2,000 2,000 2,000 2,000 2,000 REX Clarington West 2,400 2,400 2,400 2,400 2,400 Nexus 2,000 2,000 2,000 2,000 2,000 TETCO A2M 1,000 Total - 600 600 950 950 950 2,150 2,708 2,708 2,708 2,708 4,958 4,958 4,958 8,308 12,708 12,708 12,708 12,708 13,708

Wet Marcellus & Utica Takeaway projects to the MidAtlantic and the SouthTGP Backhaul 500 500 500 500 500 500 500 500 500 500 500 500 500 500 500 500 500 500 500 TETCO TEAM 2014 600 600 600 600 600 600 600 600 600 600 600 600 600 600 600 600 600 TETCO TEAM South 300 300 300 300 300 300 300 300 300 300 300 300 300 300 300 300 300 TCO West Side Expansion 444 444 444 444 444 444 444 444 444 444 444 444 444 444 444 444 444 TETCO OPEN 550 550 550 550 550 550 550 550 550 550 550 550 550 TGP Broad Run Flexibil ity 590 590 590 590 590 590 590 590 590 590 590 590 590 TGP Utica Backhual 352 352 352 352 352 352 352 352 352 352 352 352 352 TCO Leach Express 1,000 1,000 1,000 1,000 1,000 1,000 1,000 1,000 1,000 TETCO Gulf Project II 250 250 250 250 250 250 250 250 250 TGT OH-LA Access 626 626 626 626 626 626 626 626 626

TGT Northern Supply Access 584 584 584 584 584 584 584 TGP SW Louisiana 900 900 900 900 900 900 TGP Broad Run Expansion 200 200 200 200 200 TETCO Gulf Project II (Phase 2) 400 400 400 400 400 TETCO Adair Southwest 200 200 200 200 200 TETCO Access South 320 320 320 320 320 TCO Mountaineer Xpress 750 Dominion Atlantic Coast Pipeline 1,500 Transco Appalachian Connector 1,000 Total - 500 500 1,844 1,844 1,844 1,844 3,336 3,336 3,336 3,336 5,212 5,212 5,796 6,696 7,816 7,816 7,816 7,816 11,066

Cumulativ e Total to: - 1,100 1,100 3,124 3,124 3,124 4,324 7,367 8,017 8,017 8,017 12,761 12,761 13,345 19,295 24,815 24,965 25,965 26,465 33,915 Northeast Premium - - - 330 330 330 330 488 1,138 1,138 1,138 1,756 1,756 1,756 1,756 1,756 1,906 1,906 1,906 5,106 MidAtlantic/South - 500 500 1,844 1,844 1,844 1,844 4,171 4,171 4,171 4,171 6,047 6,047 6,631 9,231 10,351 10,351 11,351 11,851 15,101 MidCon/Canada - 600 600 950 950 950 2,150 2,708 2,708 2,708 2,708 4,958 4,958 4,958 8,308 12,708 12,708 12,708 12,708 13,708


57


Major Takeaway Pipelines for Canadian Gas

AECO/NIT

A/BC

Malin

Opal Cheyenne

Dawn/Union SWDA

Meeker

Monchy

Empress Union WDA

Chicago Wamsutter

Clarington

North Bay

Crystal Falls

Dominion Southpoint

New York

McNeil Kingsgate

Carlton

Emerson

Joliet

Reno Harper

Iroquois

Sumas

Medford

1

2

3

4

5

6

7 8

1.) TransCanada Mainline

2.) Northern Border

3.) TransCanada GTN

4.) Ruby

5.) Rockies Express

6.) TransCanada Great Lakes

7.) Bison

8.) Iroquois

Buffalo

Source: Morgan Stanley Commodity Research estimate


58


Firm Transportation Costs

AECO/NIT

A/BC

Malin

Opal Cheyenne

Dawn/Union SWDA

Meeker

Monchy

Empress Union WDA

Chicago Wamsutter

Clarington

North Bay

Crystal Falls

$0.64

Dominion Southpoint

New York $1.14

$0.19

$0.10

$0.44

$1.65

$0.88 McNeil

Kingsgate

$0.12

Carlton

Emerson

Joliet

$0.16

$0.19

$0.40

Reno

$0.45

$0.38

Harper

$0.40

$0.12

$0.07

$0.33 Iroquois

$.041

1.) Empress to Dawn (via Great

Lakes): $1.095

2.) Empress to Dawn/Union CDA (via

TC Mainline): $1.59

3.) AECO to Chicago (via Northern

Border): $0.75

4.) AECO to Malin (via TC GTN):

$0.70

5.) Cheyenne to Clarington (via

REX): $1.6585

6.) AECO to Iroquois (via TC

Mainline): $1.894

7.) Opal to Marlin (via Ruby): $1.14

$0.57 Sumas

Medford

$0.57

Buffalo



59


Major Northeast Pipelines

Source: Range Resources, Morgan Stanley Commodity Research


60


Northeast Gas Trading Hubs

Source: EIA, SNL, Morgan Stanley Commodity Research


61


TC Mainline

PNW

Bison Great Lakes

ANR Southern

Star

REX CPGP

Northern Border

Pipelines and Firm Transportation Costs

CIG

Iroquois

1.) Empress to Dawn (via Great

Lakes): $1.095

2.) Empress to Dawn/Union CDA (via

TC Mainline): $1.59

3.) AECO to Chicago (via Northern

Border): $0.823

4.) AECO to Malin (via TC GTN):

$0.70

5.) Cheyenne to Clarington (via

REX): $1.10

6.) AECO to Iroquois (via TC

Mainline): $1.894

7.) Opal to Marlin (via Ruby): $0.68-

$0.76

Trail Blazer

TETCO

Ruby

$1.095 $1.59

$0.823 $0.70

$1.10

$1.894

$0.68 – 0.76



62


US Natural Gas Balance (Monthly)

Source: EIA, HPDI, NOAA, Bentek, Morgan Stanley Commodities Research estimates

Jan-14 Feb-14 Mar-14 Apr-14 May-14 Jun-14 Jul-14 Aug-14 Sep-14 Oct-14 Nov-14 Dec-14 Jan-15 Feb-15 Mar-15 Apr-15 May-15 Jun-15 Jul-15 Aug-15 Sep-15 Oct-15 Nov-15 Dec-15SUPPLYGross Production L48 75.4 75.1 76.2 76.8 77.7 78.3 78.7 80.3 80.4 81.0 81.2 80.6 80.7 80.5 80.4 80.4 81.0 81.6 81.6 81.5 81.4 81.4 81.9 82.3

YoY 2.9 2.3 3.6 3.6 4.5 5.5 4.0 5.9 6.9 6.9 6.8 8.1 5.3 5.4 4.2 3.6 3.3 3.3 2.9 1.2 0.9 0.4 0.7 1.7

L48 Gas (Conventional) 28.7 28.5 28.2 28.0 27.8 27.6 27.4 27.2 27.0 26.7 26.5 26.3 26.1 25.9 25.7 25.5 25.3 25.1 24.9 24.7 24.5 24.3 24.2 24.0CBM 3.2 3.1 3.1 3.0 3.0 3.0 2.9 2.9 2.9 2.9 2.9 2.8 2.7 2.6 2.6 2.5 2.5 2.5 2.4 2.4 2.4 2.4 2.4 2.3Onshore L48 Shale 31.2 31.5 31.6 32.0 32.5 32.9 32.9 33.0 33.2 33.7 34.0 34.2 34.4 34.5 34.7 34.8 34.9 35.3 35.5 35.8 35.8 36.1 36.7 37.3

YoY 1.69 1.83 1.74 1.70 1.55 1.48 2.40 2.39 2.51 2.74 2.5 2.4 3.2 3.0 3.10 2.7 2.4 2.3 2.6 2.7 2.6 2.35 2.7 3.2

Barnett 4.9 4.8 4.8 4.7 4.6 4.6 4.5 4.5 4.4 4.4 4.3 4.3 4.2 4.2 4.2 4.1 4.1 4.1 4.0 4.0 4.0 3.9 3.9 3.9Fayetteville 2.8 2.8 2.8 2.8 2.8 2.8 2.8 2.8 2.8 2.8 2.8 2.8 2.8 2.8 2.8 2.8 2.8 2.8 2.8 2.8 2.8 2.8 2.8 2.8Woodford 0.8 0.7 0.7 0.7 0.7 0.7 0.7 0.7 0.7 0.7 0.7 0.7 0.7 0.7 0.7 0.7 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6Haynesville 5.3 5.3 5.1 5.1 5.1 5.0 5.0 5.0 4.9 4.9 4.9 4.9 4.9 5.0 5.0 5.0 5.0 5.0 4.9 4.8 4.8 4.7 4.7 4.7

Haynesville (LA) 4.4 4.5 4.3 4.3 4.3 4.3 4.2 4.2 4.2 4.2 4.2 4.2 4.1 4.1 4.1 4.1 4.1 4.1 4.1 4.0 4.0 4.0 4.0 4.0Haynesville (TX) 0.8 0.8 0.8 0.8 0.8 0.8 0.8 0.7 0.7 0.7 0.7 0.7 0.8 0.8 0.9 0.9 0.9 1.0 0.8 0.8 0.7 0.7 0.7 0.6

Marcellus 9.7 10.0 10.2 10.7 11.0 11.5 11.5 11.5 11.7 12.1 12.2 12.4 12.4 12.3 12.4 12.3 12.3 12.6 12.9 13.1 13.1 13.3 13.8 14.2SW Marcellus 2.7 2.7 2.6 2.8 2.8 3.0 3.1 3.1 3.3 3.5 3.6 3.8 3.8 3.8 3.8 3.8 3.8 4.0 4.3 4.4 4.4 4.5 4.7 4.9NE Marcellus 7.0 7.3 7.6 7.9 8.2 8.4 8.4 8.4 8.4 8.5 8.6 8.6 8.6 8.6 8.6 8.5 8.5 8.6 8.6 8.6 8.6 8.8 9.1 9.3

WV 1.7 1.7 1.8 1.8 1.9 1.9 2.0 2.0 2.1 2.1 2.2 2.2 2.3 2.3 2.4 2.4 2.5 2.5 2.6 2.6 2.7 2.7 2.8 2.8Eagle Ford 2.8 2.8 2.8 2.8 2.9 2.8 2.8 2.8 2.8 2.8 2.8 2.8 2.9 2.9 3.0 3.0 3.0 3.1 3.1 3.1 3.2 3.2 3.2 3.3Utica 0.6 0.7 0.7 0.8 0.9 1.0 1.1 1.1 1.2 1.4 1.5 1.5 1.6 1.6 1.7 1.8 1.8 1.9 1.9 2.0 2.0 2.1 2.2 2.4Other Shale 2.7 2.7 2.7 2.7 2.7 2.7 2.7 2.7 2.7 2.7 2.7 2.7 2.7 2.7 2.7 2.7 2.7 2.7 2.7 2.7 2.7 2.7 2.7 2.7

Onshore L48 Associated 8.4 8.9 9.1 9.7 10.0 10.3 10.5 10.6 10.7 10.8 11.0 11.2 11.4 11.3 11.2 11.4 12.1 12.2 12.3 12.1 12.1 12.1 12.2 12.2YoY 2.4 2.5 2.6 2.9 3.1 3.1 3.1 3.1 3.0 2.9 3.0 3.1 3.0 2.4 2.2 1.8 2.1 1.9 1.8 1.6 1.4 1.3 1.1 1.0

Bakken 0.6 0.7 0.7 0.8 0.8 0.9 0.9 0.8 0.9 0.9 0.9 0.9 0.8 0.8 0.8 0.8 0.9 0.9 0.9 0.9 0.9 0.8 0.8 0.8Eagle Ford 1.5 1.6 1.7 1.9 2.1 2.2 2.2 2.2 2.2 2.2 2.3 2.3 2.7 2.8 2.7 2.8 2.7 2.8 2.8 2.8 2.7 2.7 2.7 2.7Permian 2.2 2.3 2.5 2.6 2.7 2.7 2.8 2.8 2.8 2.9 3.0 3.1 3.4 3.2 3.3 3.4 3.4 3.3 3.4 3.4 3.4 3.5 3.5 3.6Mississippian 0.6 0.7 0.6 0.6 0.6 0.7 0.7 0.7 0.7 0.7 0.7 0.7 0.7 0.8 0.7 0.7 0.7 0.7 0.7 0.6 0.7 0.6 0.6 0.6Denver Julesberg 1.0 1.0 0.9 0.8 0.8 0.8 0.8 0.9 0.9 0.9 0.9 0.9 0.9 0.9 0.8 0.8 0.8 0.8 0.7 0.7 0.7 0.7 0.7 0.7Utica Oil 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.2 0.2 0.2 0.2 0.2 0.2 0.3 0.3 0.3 0.3 0.3 0.3 0.3 0.3 0.3 0.3 0.3Other Associated 2.4 2.5 2.6 2.7 2.8 2.9 3.0 3.0 3.0 3.1 3.1 3.2 2.6 2.6 2.6 2.6 3.5 3.5 3.5 3.4 3.4 3.4 3.5 3.5

Offshore GOM 3.3 3.4 3.3 3.5 3.5 3.4 3.4 3.5 3.5 3.5 3.4 3.3 3.1 3.2 3.2 3.3 3.3 3.3 3.2 3.3 3.3 3.3 3.3 3.1YoY -0.7 -0.5 -0.5 -0.4 -0.2 0.0 -0.2 0.1 -0.1 0.2 -0.2 -0.2 -0.2 -0.2 -0.2 -0.2 -0.2 -0.2 -0.2 -0.2 -0.2 -0.2 -0.2 -0.2

Balancing 3.9 3.2 4.2 4.1 4.4 4.5 5.0 6.7 6.7 6.8 6.8 6.2 6.2 6.2 6.2 6.2 6.2 6.5 6.5 6.5 6.5 6.5 6.5 6.5Dry Production L48 67.8 67.5 68.2 68.6 69.5 69.8 70.1 71.6 71.7 72.2 72.8 72.2 72.3 72.1 71.9 72.0 72.6 73.2 73.2 73.1 72.9 73.0 73.5 73.9

YoY 3.3 2.7 3.7 3.5 4.2 4.7 3.2 4.8 5.3 5.5 5.1 6.6 4.6 4.6 3.7 3.4 3.1 3.3 3.1 1.5 1.2 0.7 0.7 1.7

NET IMPORTSCanada 6.6 5.6 4.5 4.4 5.0 4.6 4.5 5.1 4.8 5.2 4.7 5.9 6.1 5.1 4.0 4.2 4.8 4.4 4.3 4.9 4.6 5.0 4.5 5.7

YoY 1.3 0.6 -0.2 -0.4 0.2 -0.5 -0.7 0.0 -0.4 0.5 -0.5 -0.5 -0.5 -0.5 -0.5 -0.2 -0.2 -0.2 -0.2 -0.2 -0.2 -0.2 -0.2 -0.2

Mexico (1.7) (1.8) (1.8) (1.9) (2.0) (2.2) (2.2) (2.1) (2.1) (1.9) (2.2) (1.9) (2.2) (2.3) (2.3) (2.4) (2.5) (2.7) (2.7) (2.6) (2.6) (2.4) (2.7) (2.4) YoY 0.1 -0.1 0.0 -0.1 -0.1 -0.2 -0.2 -0.1 -0.4 -0.2 -0.5 -0.5 -0.5 -0.5 -0.5 -0.5 -0.5 -0.5 -0.5 -0.5 -0.5 -0.5 -0.5 -0.5

LNG 0.3 0.1 0.1 0.1 0.1 0.3 0.2 0.1 0.2 0.2 (0.0) (0.0) 0.1 0.0 (0.0) (0.0) (0.0) 0.2 0.1 (0.1) 0.1 0.1 (0.7) (0.7) YoY -0.2 -0.3 -0.2 -0.1 -0.1 0.1 -0.1 -0.2 -0.4 0.0 -0.1 -0.1 -0.1 -0.1 -0.1 -0.1 -0.1 -0.1 -0.1 -0.1 -0.1 -0.1 -0.6 -0.6

Total Net Imports 5.2 4.0 2.8 2.7 3.1 2.7 2.5 3.0 2.8 3.5 2.5 3.9 4.1 2.8 1.6 1.8 2.2 1.9 1.7 2.2 2.0 2.7 1.2 2.6 YoY 1.2 0.2 -0.5 -0.5 0.1 -0.7 -1.0 -0.4 -1.2 0.3 -1.1 -1.1 -1.1 -1.1 -1.1 -0.8 -0.8 -0.8 -0.8 -0.8 -0.8 -0.8 -1.3 -1.3

DEMANDResidential/Commercial 51.0 47.7 35.5 19.9 12.1 8.8 7.8 7.7 8.7 12.7 29.4 37.2 48.5 43.8 31.6 19.3 12.5 9.0 7.4 7.7 8.4 14.2 25.4 40.4

YoY 7.4 5.6 1.5 -0.7 0.4 0.0 -0.1 -0.2 0.1 -1.1 0.6 -5.5 -2.6 -3.9 -3.9 -0.6 0.3 0.2 -0.4 0.0 -0.3 1.5 -4.0 3.2

Electric Power 21.3 19.8 18.0 18.3 20.9 24.0 27.1 28.8 25.6 22.6 20.4 21.0 20.0 19.2 17.4 20.9 24.3 28.1 33.5 32.9 28.9 24.0 21.3 21.9 YoY 1.0 -0.4 -1.4 -0.4 1.1 -0.5 -2.1 -0.1 0.6 2.1 0.4 -0.3 -1.3 -0.6 -0.6 2.6 3.4 4.1 6.4 4.0 3.3 1.4 0.9 0.9

Industrial Demand 23.3 23.7 22.0 20.9 19.6 19.6 19.6 19.7 19.7 19.7 21.2 22.0 22.8 22.6 22.2 21.2 20.3 19.8 19.6 19.6 19.9 20.7 22.0 23.6 YoY 1.5 1.5 1.0 0.9 0.5 0.8 1.0 0.6 0.6 0.0 -0.5 -0.8 -0.5 -1.1 0.2 0.3 0.7 0.2 0.0 -0.1 0.2 1.0 0.8 1.7

Vehicle Demand 0.09 0.09 0.09 0.09 0.09 0.09 0.09 0.09 0.09 0.09 0.09 0.09 0.09 0.09 0.09 0.09 0.09 0.09 0.09 0.09 0.09 0.09 0.09 0.09 YoY 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0

Lease Plant/Pipeline Fuel 7.8 7.6 7.2 6.6 6.5 6.5 6.6 6.8 6.7 6.8 7.3 7.6 8.2 8.0 7.6 7.1 7.0 7.0 7.2 7.2 7.1 7.2 7.5 8.1 YoY 0.8 0.6 0.5 0.5 0.6 0.6 0.5 0.6 0.7 0.7 0.5 0.4 0.4 0.4 0.4 0.5 0.5 0.5 0.6 0.4 0.4 0.4 0.3 0.5

Total Demand 103.6 98.9 82.8 65.8 59.2 58.9 61.2 63.0 60.9 61.9 78.2 87.8 99.6 93.8 78.8 68.6 64.2 64.1 67.8 67.4 64.5 66.2 76.2 94.2 YoY 10.7 7.3 1.5 0.4 2.7 0.9 -0.8 0.9 2.0 1.7 1.0 -6.2 -4.0 -5.1 -4.0 2.8 5.0 5.1 6.6 4.3 3.6 4.3 -2.0 6.3

BALACING ITEM (0.1) 1.6 0.8 1.7 1.9 1.7 1.7 0.6 0.6 (0.3) (2.2) (1.1) (0.1) 1.6 0.8 1.7 1.9 1.7 1.7 0.6 0.6 (0.3) (2.2) (1.1)

STORAGE INJ/WTH (Bcf) (950) (725) (341) 214 476 459 406 377 428 420 (156) (397) (721) (485) (138) 206 391 379 270 265 331 283 (114) (582) Bcf/d (30.7) (25.9) (11.0) 7.1 15.4 15.3 13.1 12.2 14.3 13.6 (5.2) (12.8) (23.3) (17.3) (4.5) 6.9 12.6 12.6 8.7 8.5 11.0 9.1 (3.8) (18.8)

Ending Storage 1,925 1,200 857 1,066 1,548 2,005 2,402 2,770 3,190 3,590 3,434 3,037 2,316 1,831 1,693 1,900 2,290 2,670 2,940 3,205 3,536 3,819 3,705 3,123


63


US Natural Gas Balance (Annual)

Source: EIA, HPDI, NOAA,Bentek, Morgan Stanley Commodities Research estimates

Sum

mar

ySU

PPLY

2006

2007

2008

2009

2010

2011

2012

2013

2014

2015

Gro

ss P

rodu

ctio

n L4

855

.758

.060

.762

.364

.769

.372

.173

.478

.581

.2Y

oY2.

32.

71.

62.

44.

62.

71.

35.

12.

8L4

8 G

as (C

onve

ntio

nal)

48.8

40.6

40.9

39.1

36.0

33.4

33.9

30.2

27.5

25.0

YoY

-8.2

0.3

-1.8

-3.2

-2.6

0.5

-3.7

-2.7

-2.5

CBM

3.6

5.5

5.5

5.5

5.3

4.9

4.2

3.5

3.0

2.5

YoY

1.9

0.0

0.0

-0.3

-0.4

-0.7

-0.7

-0.6

-0.5

Ons

hore

L48

Sha

le2.

05.

57.

810

.815

.923

.328

.830

.632

.735

.5Y

oY3.

42.

43.

05.

17.

45.

51.

92.

12.

7Ba

rnet

t2.

03.

04.

44.

95.

15.

75.

85.

34.

64.

1Fa

yett

evill

e0.

00.

20.

71.

42.

12.

62.

82.

82.

82.

8W

oodf

ord

0.0

0.2

0.5

0.9

0.9

0.8

0.9

0.9

0.7

0.6

Hayn

esvi

lle0.

00.

00.

11.

34.

58.

18.

36.

25.

04.

9Ha

ynes

ville

(LA

)0.

00.

00.

11.

34.

06.

87.

05.

14.

34.

1Ha

ynes

ville

(TX)

0.0

0.0

0.0

0.0

0.6

1.2

1.3

1.0

0.8

0.8

Mar

cellu

s0.

00.

00.

00.

41.

13.

15.

98.

711

.212

.9SW

Mar

cellu

s0.

00.

00.

00.

30.

41.

11.

92.

53.

14.

2NE

Mar

cellu

s0.

00.

00.

00.

10.

72.

04.

16.

28.

18.

7W

V0.

00.

00.

00.

00.

00.

40.

81.

21.

92.

6Ea

gle

Ford

0.0

0.0

0.0

0.0

0.3

1.0

2.0

2.7

2.8

3.1

Utic

a0.

00.

00.

00.

00.

00.

00.

00.

11.

01.

9O

ther

Sha

le0.

02.

02.

11.

91.

81.

62.

32.

72.

72.

7O

nsho

re L

48 A

ssoc

iate

d6.

96.

56.

46.

87.

67.

85.

27.

210

.111

.9Y

oY-0

.4-0

.10.

40.

70.

2-2

.62.

02.

91.

8Ba

kken

0.0

0.0

0.0

0.0

0.0

0.0

0.5

0.6

0.8

0.8

Eagl

e Fo

rd0.

00.

00.

00.

00.

00.

00.

61.

22.

02.

7Pe

rmia

n0.

00.

00.

00.

00.

00.

01.

92.

12.

73.

4M

issi

ssip

pian

0.0

0.0

0.0

0.0

0.0

0.0

0.3

0.5

0.7

0.7

Denv

er J

ules

berg

0.0

0.0

0.0

0.0

0.0

0.0

0.3

0.7

0.9

0.8

Utic

a O

il0.

00.

00.

00.

00.

00.

00.

00.

00.

10.

3O

ther

Ass

ocia

ted

6.9

6.5

6.4

6.8

7.6

7.8

1.7

2.0

2.9

3.2

Offs

hore

GO

M8.

07.

76.

46.

76.

25.

04.

23.

63.

43.

2Ba

lanc

ing

0.0

0.0

0.0

0.0

0.0

0.0

0.0

1.8

5.2

6.4

Dry

Prod

uctio

n L4

849

.551

.754

.055

.557

.461

.864

.865

.870

.272

.8Y

oY2.

12.

41.

41.

94.

43.

01.

04.

42.

6NE

T IM

PORT

SCa

nada

8.9

9.0

8.3

7.0

7.0

6.0

5.4

5.1

5.1

4.8

YoY

0.2

-0.8

-1.2

-0.1

-1.0

-0.5

-0.3

-0.1

-0.3

Mex

ico

-0.9

-0.8

-1.0

-0.9

-0.9

-1.3

-1.7

-1.8

-2.0

-2.5

YoY

0.1

-0.2

0.1

0.0

-0.4

-0.3

-0.1

-0.2

-0.5

LNG

1.6

2.1

1.0

1.2

1.2

1.0

0.5

0.3

0.1

-0.1

YoY

0.5

-1.1

0.3

-0.1

-0.2

-0.5

-0.2

-0.1

-0.2

Tota

l Net

Impo

rts9.

610

.48.

27.

47.

25.

64.

23.

63.

22.

2Y

oY0.

7-2

.1-0

.9-0

.1-1

.6-1

.3-0

.6-0

.4-1

.0DE

MAN

DRe

side

ntia

l/Com

mer

cial

19.8

21.4

22.0

21.7

21.7

21.7

19.3

22.5

23.2

22.3

YoY

1.5

0.7

-0.3

0.0

0.0

-2.4

3.3

0.7

-0.9

Elec

tric

Pow

er17

.018

.718

.218

.820

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64


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