Natural Gas Winter Arrives, But Will It Last?

MORGAN
NORTH
STANLEY
RESEARCH
AMERICA
Morgan Stanley & Co. LLC
Adam Longson, CFA, CPA
[email protected]
+1 212 761 4061
Stefan Revielle
[email protected]
+1 212 761 6005
November 11, 2014
Natural Gas
Winter Arrives, But Will It
Last?
Morgan Stanley Natural Gas Price Forecast
(MS average Henry Hub Price Forecast, $/MMBtu)
$6.00
Recent rally primarily a result of positioning, fear
and short-term weather. After last winter, it’s no
surprise that the market is quick to react to any sign of
cold. However, we see limited upside from here without
a pronounced change in the longer-term winter forecast.
Upcoming cold is the result of a rare storm system
moving into Alaska, not a sustained change in weather
patterns as evidenced by warming late-Nov forecasts.
Financial positioning also appears to be a greater driver
of recent price action, rather than a bullish bet on natural
gas. We continue to believe a very cold winter is
required to see material upside in natural gas prices, as
we see a number of both fundamental and financial
headwinds that could limit upside for now (or drive some
reversal).
Bull
$5.50
$5.00
$4.73
$4.58
$4.75
$4.50
$3.94
$4.50
$4.05
Forward
curve
Base
$4.00
$3.50
$3.50
$3.50
$3.00
Bear
$3.75
$2.50
1Q14
2Q14
3Q14e 4Q14e
2015e
Legend
Source: Bloomberg, Morgan Stanley Commodity Research
Much Below Normal Temperatures Expected
in the North Central and Northeast US
(NOAA 6-10 day outlook, valid for Nov 17-21)
Further near term upside may be limited. Not only is
the worst of the cold likely already priced in, but we see a
number of medium term headwinds: 1) Fundamentals
continue to show robust supply with more NE
infrastructure coming online. 2) Associated gas growth
concerns are likely overblown. 3) Short covering may
have been a bigger driver in the recent rally than new
longs. 4) To-date, cash prices gains have failed to rival
prompt month rally. 5) Under hedged producers are
likely to act, with downward price pressure to follow. We
believe some of these headwinds are already playing
out in the selloff over the past few days.
Regional balances have changed, shifting exposure
to a repeat of winter 13/14. We don’t want to dismiss
the growing risk that another harsh winter, but the
impact would likely not be as severe. The NE is more
protected with more production, improved inventories
and better interconnectivity. However, the Western
Canadian and New England markets are at risk of price
spikes in a repeat of last winter. Unlike the L48, less
robust supply growth in the WCSB, and strong US
exports have kept Western Canada at a sizable YoY
inventory deficit. In New England, little change to gas
infrastructure and nuke retirements should support price
premiums and volatility during cold winter days.
Source: NOAA, Morgan Stanley Commodity Research
For important disclosures, refer to the
Disclosures Section, located at the end of
this report.
MORGAN
STANLEY
RESEARCH
November 11, 2014
Economics
Exhibit 1
Physical Cash Prices Have Yet To Show Stress
(left axis: HH prompt – spot, $/MMBtu; right axis: HH futures and spot prices,
$/MMBtu)
$8.00
$0.40
$7.50
$0.20
$7.00
$6.50
$0.00
$6.00
-$0.20
$5.50
-$0.40
$5.00
$4.50
-$0.60
$4.00
-$0.80
$3.50
$3.00
Prompt Future - Cash (LHS)
Prompt Future (RHS)
Oct-14
Nov-14
Sep-14
Sep-14
Jul-14
Aug-14
Jul-14
Jun-14
Apr-14
May-14
Apr-14
Mar-14
Feb-14
Jan-14
Feb-14
Dec-13
Dec-13
Oct-13
Nov-13
-$1.00
Oct-13
Recent Rally More Related to Positioning and Fear, and
May Have Limited Upside. After last winter, it’s no surprise
that the market is quick to react to any sign of cold weather.
However, we see limited upside from here without a
pronounced change in the longer term winter weather forecast.
The upcoming cold is a reflection of a rare storm system
moving into Alaska, not a sustained change in weather
patterns. Furthermore, financial positioning appears to be a
greater driver of recent price action, rather than a bullish bet on
natural gas. We continue to believe a very cold winter is
required to see material upside in natural gas prices, as we see
a number of both fundamental and financial headwinds that
could limit upside for now (or even cause some reversal). In
fact, we believe some of this dynamic is already playing out in
the selloff over the past few days.
HH Spot (RHS)
Source: CME, Morgan Stanley Commodity Research
Short covering may have been a bigger driver in the
recent rally than new longs. Managed money net position
was net long by just 75K contracts across all futures exchanges
as of Oct 28, the lowest level since Apr 2012 and 513K less
length than its Feb peak. Since Sep, managed money net
length had declined 142K contracts and Cal 2015 prices fell 22
cents thanks to record supply growth and initial prospects for a
warmer than normal Nov. With positioning so short, it should be
no surprise that an abrupt change in the weather outlook drove
a run up in futures prices –especially after the price action last
winter. However, we believe much of the rally has been the
result of short covering rather than fundamental buyers who
typically provide more staying power in bullish price runs as
proven by the 33K increase in Managed Money positions from
Oct 28 to Nov 4. Our view is also partly corroborated by the
slight easing in futures prices over the past few days.
Exhibit 2
Managed Money Positioning Was Too Short
(LHS: Disaggregated CFTC data for Managed Money net position, # of contracts,
RHS: 12 month average HH prices, $/MMbtu)
800,000
$5.00
$4.75
600,000
$4.50
$4.25
400,000
$4.00
200,000
$3.75
$3.50
0
$3.25
-200,000
Jan-13
$3.00
Apr-13
Jul-13
Nov-13
NYMEX MMNet
NYMEX Swap MM Net
NYMEX Euro Style Opt MM Net
ICE Pen MMNet
Generic 12 mo stip (rhs)
Feb-14
Jun-14
Sep-14
ICE HH OTC MM Net
NYMEX HH Pen Swap MM Net
HH Last Day Fin MM Net
Total
Source: CFTC, NYMEX, ICE, Morgan Stanley Commodity Research
Exhibit 3
To-date, cash prices gains have failed to rival prompt
month rally. While it is not rare to see cash/prompt price
divergence, the key fundamental spread is at recent highs
pointing to a physical/financial disconnect. At the time of
writing, cash henry hub prices remain 20 cent under Dec Henry
Hub futures prices, meaning physical buyers have yet to enter
the market in advance of recent cold forecasts. Such
divergences cannot persist for long. Either physical markets
need to confirm the signal (and they could next week), or
futures need to come back to reality. Regardless, the
physical/financial disconnect doesn’t bode well for further
upside in futures given much of the “good news” is already
priced in. Thus far, it appears we are seeing both some
improvement in cash and retreat of futures.
Producer/Merchant/Processor (PMP) May Have An
Opportunity to Hedge
(LHS: Disaggregated CFTC data for PMP net position, # of contracts, RHS:
reverse 12 month average HH prices, $/MMbtu)
$0.00
600,000
$1.00
400,000
$2.00
$3.00
200,000
$4.00
$5.00
0
$6.00
-200,000
$7.00
Jan-10 Aug-10 Mar-11 Sep-11 Apr-12 Nov-12 Jun-13 Jan-14 Aug-14
NYMEX PMP Net
NYMEX Swap PMP Net
NYMEX Euro Style Opt PMP Net
ICE Pen PMP Net
Generic 12 month strip (rhs)
ICE HH OTC PMP Net
NYMEX HH Pen Swap PMP Net
HH Last Day Fin PMP Net
Total
Source: CFTC, NYMEX, ICE, Morgan Stanley Commodity Research
2
MORGAN
STANLEY
RESEARCH
November 11, 2014
Economics
Under hedged producers are likely to act, with downward
price pressure to follow. While non-commercial investors
had positioned for downside, commercial players have logged
record net length. On the producer side, futures prices have
given limited opportunities to lock in 2015 hedges as 2015
calendar year prices. Despite optimism in early summer, the
2015 strip fell below the $4/MMbtu mark in July and has yet to
bounce back. In total, the latest CFTC data shows that the
producers, merchants and processors group held 369K in net
length as of Oct 28 which is the longest the investor group has
been positioned dating back to 2010. Given the relatively quiet
activity from the producer side, we think increased activity will
follow recent rallies and likely contribute to downside pressure.
On the consumer side, news sources suggest many NE utilities
have increased winter gas hedges, which has added to the
length.
Exhibit 4
US Storage Inventories Continue to Inject at
Seasonal Highs
(Weekly storage injections, Bcf)
130
110
90
70
50
30
10
(10)
(30)
(50)
Apr-14
Jun-14
Aug-14
09-13 range
Oct-14
Avg
2013
2014
Source: EIA, Morgan Stanley Commodity Research
Exhibit 5
Supply Side Is Likely to Remain a Problem
US Dry Gas Production Now at +70 Bcf/d
Fundamentals continue to show robust supply with
another week of injections ahead. US storage facilities in the
US have added ~2.7 Tcf this injection season, 10% more than
previous records to date. With likely one more injection left this
season, we estimate inventories will peak at ~3.62 Tcf or 211
Bcf below starting levels last winter. In the EIA East region,
where inventories were most dire last winter, the YoY storage
deficit is expected to shrink to minimal levels thanks to record
production growth and mild temperatures this summer. Even in
the EIA producing and west regions, where deficits are likely to
remain ahead of winter, the trickle-down impact of supply
growth out of the NE and fewer seasonal imports to meet NE
demand, lessens the importance of regional storage shortfalls.
(Daily US dry gas production, Bcf/d)
72
71
70
69
68
67
66
65
64
63
Oct-14
Nov-14
Sep-14
Jul-14
dry gas production
Aug-14
Jun-14
Apr-14
May-14
Mar-14
Jan-14
Feb-14
Dec-13
Oct-13
Nov-13
62
30 day MAV
Source: Bentek Energy, Morgan Stanley Commodity Research
Exhibit 6
NE production growth continues to carry supply higher
with a tailwind from new infrastructure. The Northeast
supply basins continue to drive total US supply higher with
recent pipeline estimates for the region surging past 17 Bcf/d
and pushing total US dry gas supply above 70 Bcf/d, ~4 Bcf/d
higher than the same time last year. As we speak, 8 different
NE expansion projects are experiencing varying levels of
line-fill, and are still expected to add 1.3 Bcf/d to supply ahead
of winter. So far, it is estimated that 0.3 Bcf/d of “new” supply
has entered the newly added pipes. The fact that the pace of
growth on new additions is slower than last year shouldn’t be a
surprise given more of this infrastructure is directed at SW
PA/Utica. Production growth should eventually match
expectations, but targets may take longer to reach. Given the
number of well tie-ins with this year’s expansions are
liquids-heavy and require processing (as opposed to the dry
wells in NE Marcellus last year), there may be an additional
time-lag not witnessed in 2013.
50% of Associated US Gas Supply Comes from
Plays with Breakevens Below ~$60/bbl
(y-axis: 2013 marginal breakeven price* by project on a Brent-equivalent basis,
$/bbl; x-axis: incremental production added from 2013-2018, mmb/d)
105
95
85
83
High
75
65
60
55
45
38
35
25
Avg
57
40
41
41
27
Low
15
Source: Rystad Energy, Morgan Stanley Commodity Research estimates
Note: Breakeven prices assume a 10% hurdle rate
3
MORGAN
STANLEY
RESEARCH
November 11, 2014
Economics
Exhibit 7
Associated Gas Growth Has Been High, But A Fair
Amount Never Makes It To Market
(LHS: Gross gas withdrawals from oil wells, Bcf/d; RHS: Production vented &
flared, Bcf/d)
9
1.6
8
1.4
7
1.2
6
1.0
5
0.8
4
0.6
3
0.4
2
West
2013
2012
2011
2010
2009
2008
2006
2005
2004
2007
Midwest
Vented/Flared (rhs)
Western Canada Stocks Remain At a Sizable YoY
Deficit
(Working gas storage levels, Bcf)
600
500
A repeat of winter 13/14 may have a different outcome.
While no one will deny that another harsh winter would be
bullish for natural gas, we don’t expect the same exact
outcome. As we’ve written (see Coal, Gas & Power:
300
200
100
Cross-Industry Implications of Marcellus/Utica Gas Basis;
Bearish Natgas Outlook (25 Sep 2014)), a number of one-off
number of markets this year, namely Western Canada and
New England.
South
Exhibit 8
400
Northeast Utilities in PJM having hedged 70% of their winter
gas, a 15% increase YoY, which should limit spot buying
this winter. That said, we see risk of greater upside in a
Northeast
Source: EIA 2013 Natural Gas Annual, Morgan Stanley Commodities Research
Note: All totals exclude AK volumes and 2013 data may not be complete
New Regional Issues Will Continue to Emerge
issues compounded the challenges in the NE last winter that
are unlikely to repeat to the same degree (freeze offs, a
compressor failing, etc.). With storage, production,
interconnectivity and reliability all improved in the NE YoY, we
don’t expect the same upside without some major issue in the
supply chain, namely with coal deliverability. Similarly, Eastern
Canada storage is higher YoY despite nearly fully depleting
last winter. These dynamics may result in less call on imports
from other regions, which could support storage better than last
winter. Moreover, news sources point to the fact that many
2003
0.0
2002
0.2
0
2001
1
2000
Associated gas growth concerns overblown? Gas supplies
associated with oil-directed drilling have contributed a
significant amount, between 2-3 Bcf/d per annum, over the
past two years. While the decline in oil prices has created
concern about this supply source, we see a number of offsets
that should support associated gas next year. 1) Exceptionally
low breakevens in the Eagle Ford and Permian, where 50% of
associated gas is produced, likely shields most growth. 2)
According to EIA, 20% of L48 associated gas production was
reinjected in 2013 (mostly TX), while ~11% was flared (mostly
TX and ND), limiting the market impact. High gas flaring and
reinjection negates the gas market impact of a marginal
pullback in the basin. 3) Thus far, NGL prices have not been
materially impacted by oil price moves, but lower oil prices can
result in declining NGL margins and frac spreads, increasing
the likelihood of ethane rejection, which boosts gas supply. 4)
Oil price declines can lead to reallocation of CAPEX to some
previously marginal gas plays, 5) Lower freight fuel costs lead
to lower coal prices and potentially gas prices due to coal/gas
switching economics. 6) Oil producer inertia (hedging, debt
covenant obligations, midstream agreements, and rig
contracts) may also limit the magnitude of slowdown in the near
term.
0
Jan-14
Mar-14
May-14
5-yr Range
Jul-14
2013
Sep-14
2014
Nov-14
5-yr Avg
Source: Enerdata, Morgan Stanley Commodity Research
Exhibit 9
Alberta/BC/Saskatchewan Production Has
Responded Little to Higher Prices
(Natural gas production, Bcf/d)
15.00
14.50
14.00
13.50
13.00
12.50
12.00
11.50
Jan
Feb
Mar
Apr
5-Y range
May
Jun
5-Y avg
Jul
Aug Sep
2013
Oct
Nov
Dec
2014
Source: Company Data, Morgan Stanley Commodity Research
4
MORGAN
STANLEY
RESEARCH
November 11, 2014
Economics
In Western Canada, low stocks and lagging supply growth
leaves AECO prone to price spikes. Like the US, stocks in
Canada were hit hard during last winter’s multiple polar vortex
events. Stocks in Western Canada began the injection season
at a 190 Bcf YoY storage deficit while stocks in Eastern
Canada nearly fully depleted. While Eastern Canada has
largely recovered and is nearly 100% full heading into winter (a
YoY surplus), Western Canadian stocks remain 26% lower
than last year and at 5-year lows. Unlike the US, Canadian gas
production growth has lagged, growing only 0.4 Bcf/d YoY YTD
despite prices in Alberta averaging $1.20/MMbtu higher YoY.
Subsequently, we see the region susceptible to price spikes
similar to last year, and certainly if winter cold rivals last winter.
The caveat is that higher Eastern Canadian stocks and a
potential lower pull on Canadian exports from the NE could
keep Western Canada more balanced than starting inventories
would suggest.
In New England, infrastructure and limited supply
optionality should keep winter Algonquin prices bid. While
the greater Appalachian market is undergoing another wave of
infrastructure additions, improving connectivity throughout the
region, New England gas markets have yet to benefit from
nearby cheap gas. We caution that not only has infrastructure
feeding the greater Boston market not changed YoY, leaving
potential for gas supply shortfalls this winter, but the retirement
of the 620 MW Vermont Yankee facility will also add to market
tightness. Therefore, in a similar winter event as last year, the
region would likely experience similar type pricing spikes just to
attract supply molecules to meet demand peaks. At a
minimum, New England may need to compete with global
markets for LNG supply which fortunately have fallen with the
recent oil price decline.
5
MORGAN
STANLEY
RESEARCH
November 11, 2014
Economics
Exhibit 10
Morgan Stanley US Natural Gas Supply Demand Balance
SUPPLY
Gross Production L48
YoY
Jan-14
Feb-14
Mar-14
Apr-14
May-14
Jun-14
Jul-14
Aug-14
75.4
75.1
76.2
76.8
77.7
78.3
78.7
79.6
------> Forecast
Sep-14
Oct-14
77.8
79.0
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
79.3
79.3
80.5
80.1
80.8
80.9
80.6
81.4
81.9
81.8
82.1
83.2
83.6
Dec-15
83.4
2.9
2.3
3.6
3.6
4.5
5.5
4.0
5.1
4.3
5.0
4.9
6.7
5.1
5.0
4.6
4.1
2.9
3.2
3.2
2.2
4.3
4.1
4.3
4.2
L48 Gas (Conventional)
CBM
Onshore L48 Shale
28.7
3.2
31.3
28.5
3.1
31.1
28.2
3.1
31.2
28.0
3.0
32.0
27.8
3.0
32.0
27.6
3.0
32.0
27.4
2.9
33.3
27.2
2.9
33.0
27.0
2.9
33.0
26.7
2.9
33.9
26.5
2.9
34.1
26.3
2.8
34.1
26.1
2.7
34.5
25.9
2.6
34.4
25.7
2.6
35.2
25.5
2.5
35.3
25.3
2.5
35.1
25.1
2.5
36.0
24.9
2.4
36.4
24.7
2.4
36.2
24.5
2.4
36.5
24.3
2.4
37.5
24.2
2.4
37.9
24.0
2.3
37.9
YoY
1.82
1.94
1.85
1.83
1.65
1.56
2.46
2.41
2.69
2.73
2.5
2.2
3.3
3.4
3.99
3.3
3.1
4.0
3.1
3.3
3.5
3.69
3.8
3.8
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
3.9
Fayetteville
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
2.8
Woodford
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
0.6
Haynesville
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
Haynesville (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
9.7
10.0
10.2
10.7
11.0
11.5
11.4
11.4
11.7
12.0
12.2
12.1
12.5
12.7
13.3
13.0
13.0
13.0
13.3
13.5
14.1
14.5
14.9
14.8
SW Marcellus
2.7
2.7
2.6
2.8
2.8
3.0
3.1
3.1
3.4
3.6
3.8
3.7
4.2
4.3
4.5
4.3
4.4
4.4
4.5
4.6
5.1
5.4
5.7
5.6
NE Marcellus
Marcellus
4.0
7.0
7.3
7.6
7.9
8.2
8.4
8.3
8.3
8.3
8.3
8.4
8.4
8.3
8.4
8.8
8.7
8.6
8.6
8.8
8.9
9.0
9.1
9.2
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
2.8
Eagle 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
3.3
Utica
0.6
0.7
0.7
0.8
0.9
1.0
1.1
1.1
1.2
1.3
1.4
1.4
1.5
1.6
1.6
1.7
1.8
1.8
1.9
1.9
2.0
2.1
2.1
Other Shale
2.8
2.3
2.3
2.6
2.2
1.7
3.1
2.7
2.3
3.0
2.9
2.9
2.8
2.3
2.3
2.6
2.2
3.0
3.1
2.7
2.3
3.0
2.9
2.9
Onshore L48 Associated
8.4
8.9
9.1
9.7
10.0
10.3
10.5
10.7
10.9
11.0
11.2
11.3
12.3
12.3
12.4
12.8
12.8
13.1
13.4
13.6
13.9
14.0
14.4
14.4
YoY
2.4
2.5
2.6
2.9
3.1
3.1
3.1
3.2
3.2
3.1
3.1
3.2
3.9
3.4
3.4
3.1
2.8
2.8
2.9
2.9
3.0
3.1
3.2
3.1
Bakken
0.6
0.7
0.7
0.8
0.8
0.9
0.9
0.9
0.9
0.9
1.0
0.9
0.9
0.9
0.9
1.0
1.0
1.0
1.0
1.0
1.1
1.1
1.1
1.1
Eagle Ford
1.5
1.6
1.7
1.9
2.1
2.2
2.2
2.2
2.2
2.3
2.3
2.4
2.7
2.8
2.7
2.8
2.8
2.9
2.9
3.0
3.0
3.0
3.1
3.1
Perm ian
2.2
2.3
2.5
2.6
2.7
2.7
2.8
2.8
2.8
2.9
2.9
2.9
3.3
3.1
3.3
3.3
3.3
3.3
3.4
3.5
3.5
3.6
3.6
3.7
Mississippian
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
0.8
0.7
0.8
0.8
0.8
0.8
0.8
0.8
0.8
Denver 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
1.0
0.9
1.0
1.0
1.1
1.1
1.2
1.2
1.3
1.3
1.3
Utica 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
Other Associated
2.4
2.5
2.6
2.7
2.8
2.9
3.0
3.0
3.1
3.1
3.2
3.2
3.5
3.5
3.5
3.6
3.6
3.7
3.8
3.9
4.0
4.0
4.1
4.1
3.3
3.4
3.3
3.5
3.5
3.4
3.4
3.4
3.2
2.9
3.2
3.1
2.9
3.0
2.9
3.1
3.1
3.1
3.0
3.0
2.9
2.6
2.8
2.7
-0.7
-0.5
-0.5
-0.4
-0.2
0.0
-0.2
0.0
-0.4
-0.4
-0.4
-0.4
-0.4
-0.4
-0.4
-0.4
-0.4
-0.4
-0.4
-0.4
-0.4
-0.3
-0.4
-0.3
Offshore GOM
YoY
Balancing
Dry Production L48
YoY
NET IMPORTS
Canada
YoY
Mexico
YoY
LNG
YoY
DEMAND
Residential/Commercial
YoY
Electric Power
YoY
Industrial Demand
YoY
Vehicle Demand
YoY
Lease Plant/Pipeline Fuel
YoY
Total Demand
YoY
BALACING ITEM
STORAGE INJ/WTH (Bcf)
Bcf/d
Ending Storage
0.3
3.8
3.6
4.6
4.1
4.9
5.4
4.7
5.9
4.2
4.6
4.7
4.8
4.8
4.9
4.9
4.8
4.8
4.7
4.8
4.8
4.8
4.8
4.8
4.8
67.8
67.5
68.2
68.6
69.5
69.8
70.1
70.9
70.3
71.2
72.1
71.9
71.3
70.9
71.3
71.2
70.9
71.5
71.9
71.7
73.6
74.4
75.4
75.1
3.3
2.7
3.7
3.5
4.2
4.7
3.2
4.1
3.8
4.5
4.4
6.3
3.6
3.5
3.1
2.6
1.4
1.7
1.8
0.8
3.3
3.2
3.3
3.2
6.6
5.6
4.5
4.4
5.0
4.6
4.5
5.1
5.0
4.4
4.7
5.9
6.1
5.1
4.0
4.2
4.8
4.4
4.3
4.9
4.8
4.2
4.5
5.7
1.3
0.6
-0.2
-0.4
0.2
-0.5
-0.7
0.0
-0.3
-0.3
-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
(1.7)
(1.8)
(1.9)
(1.9)
(2.0)
(2.2)
(2.2)
(2.1)
(2.4)
(2.2)
(1.9)
(1.9)
(2.2)
(2.3)
(2.4)
(2.4)
(2.5)
(2.7)
(2.7)
(2.6)
(2.9)
(2.7)
(2.4)
(2.4)
0.1
-0.1
-0.1
-0.1
-0.1
-0.2
-0.2
-0.1
-0.7
-0.5
-0.3
-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
(0.0)
(0.0)
(0.0)
(0.0)
(0.0)
(0.6)
(0.7)
0.3
YoY
Total Net Imports
2.2
-0.2
5.2
1.2
51.2
7.6
21.3
1.0
23.3
1.5
0.09
0.0
7.8
0.8
103.7
10.9
0.1
(951)
(30.7)
1,925
0.1
-0.3
3.9
0.2
47.7
5.6
19.8
-0.4
23.7
1.5
0.09
0.0
7.6
0.6
98.9
7.3
1.6
(726)
(25.9)
1,200
0.1
-0.2
2.7
-0.5
35.6
1.5
18.0
-1.4
22.0
1.0
0.09
0.0
7.2
0.5
82.8
1.5
0.8
(343)
(11.1)
857
0.1
-0.1
2.6
-0.5
19.8
-0.7
18.3
-0.4
20.9
0.9
0.09
0.0
6.6
0.5
65.8
0.3
0.1
-0.1
3.0
0.1
11.9
0.2
20.9
1.1
19.6
0.5
0.09
0.0
6.5
0.6
58.9
2.4
0.3
0.1
2.7
-0.7
8.8
0.0
24.0
-0.5
19.6
0.8
0.09
0.0
6.5
0.6
58.9
0.9
0.2
-0.1
2.5
-1.0
7.8
-0.1
27.1
-2.1
19.6
1.0
0.09
0.0
6.6
0.5
61.2
-0.8
0.1
-0.2
3.0
-0.4
7.6
-0.3
28.8
-0.1
19.7
0.6
0.09
0.0
6.7
0.6
62.9
0.8
1.6
1.7
1.7
1.7
1.2
213
7.1
1,066
475
15.3
1,548
459
15.3
2,005
405
13.1
2,402
378
12.2
2,769
0.4
-0.2
2.9
-1.1
8.8
0.2
24.7
-0.3
19.3
0.1
0.09
0.0
6.2
0.2
59.1
0.2
0.0
2.4
-0.8
12.5
-1.4
20.2
-0.3
19.7
0.0
0.09
0.0
6.3
0.2
58.7
-0.1
2.7
-0.9
24.9
-3.9
20.4
0.5
20.7
-1.0
0.09
0.0
6.8
0.1
72.9
-0.1
3.9
-1.1
40.8
-1.9
20.7
-0.6
22.1
-0.6
0.09
0.0
7.4
0.2
91.1
0.3
-1.5
-4.3
(0.5)
(2.2)
(2.2)
(1.1)
(10)
(0.3)
3,559
(508)
(16.4)
3,051
407
13.6
3,176
394
12.7
3,570
-2.9
0.2
-0.1
4.1
-1.1
46.4
-4.7
20.5
-0.8
22.7
-0.6
0.09
0.0
7.9
0.1
97.7
-6.0
0.1
(688)
(22.2)
2,363
0.0
-0.1
2.8
-1.1
44.4
-3.3
20.9
1.2
22.7
-1.0
0.09
0.0
7.8
0.2
95.9
-2.9
1.6
(578)
(20.6)
1,786
-0.1
1.6
-1.1
30.9
-4.6
17.9
0.0
22.2
0.2
0.09
0.0
7.3
0.1
78.4
-4.4
0.8
(145)
(4.7)
1,641
-0.1
1.8
-0.8
19.3
-0.6
22.4
4.1
21.2
0.3
0.09
0.0
6.9
0.3
69.9
4.1
-0.1
2.2
-0.8
12.2
0.3
24.3
3.4
20.4
0.8
0.09
0.0
6.7
0.3
63.7
4.8
0.2
-0.1
1.9
-0.8
9.1
0.2
28.1
4.1
19.9
0.3
0.09
0.0
6.8
0.3
63.9
5.0
0.1
-0.1
1.7
-0.8
7.4
-0.4
32.0
4.9
19.7
0.1
0.09
0.0
6.9
0.3
66.1
4.9
(0.1)
0.3
-0.1
-0.1
2.2
2.1
-0.8
-0.8
7.6
8.5
0.0
-0.3
33.1
28.5
4.3
3.8
19.6
19.9
-0.1
0.7
0.09
0.09
0.0
0.0
6.9
6.5
0.2
0.3
67.3
63.6
4.4
1.6
1.7
1.7
1.7
1.2
140
4.7
1,781
344
11.1
2,125
336
11.2
2,460
283
9.1
2,743
239
7.7
2,982
6
-0.1
-0.8
13.9
1.5
22.3
2.1
20.7
1.1
0.09
0.0
6.6
0.3
63.6
-0.6
1.4
-1.3
24.9
0.0
21.3
0.9
21.8
1.1
0.09
0.0
7.1
0.3
75.3
-0.6
2.6
-1.3
40.8
0.0
21.6
0.9
23.6
1.5
0.09
0.0
7.7
0.3
93.7
4.4
4.9
2.3
(0.5)
(2.2)
(2.2)
(1.1)
(21)
(0.7)
3,624
(532)
(17.2)
3,092
349
11.6
3,330
Source: EIA, HPDI, Bentek Energy, Morgan Stanley Commodities Research
0.1
1.6
315
10.2
3,645
2.6
MORGAN
STANLEY
RESEARCH
November 11, 2014
Economics
7
MORGAN
STANLEY
RESEARCH
November 11, 2014
Economics
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