-
Research analysts Americas Metals and Mining
Curt Woodworth, CFA - NSI [email protected] +1 212 298
4599
Alexander M. Burnes - NSI [email protected] +1 212 667
1561
Damian Karas - NSI [email protected] +1 212 298 4769
U.S. Thermal Coal Outlook
EQUITY: AMERICAS METALS AND MINING
Clear and Present Danger U.S. Thermal Coal Fundamentals Set to
Deteriorate into 2015; Downgrading BTU and ACI to Reduce U.S.
Thermal Coal Outlook From Bad to Worse We are downgrading our
thermal and coking coal price forecasts and lowering our ratings to
reduce for Peabody and Arch Coal, consistent with our bearish PRB
thesis. We believe consensus EBITDA estimates for the sector are
~20% too high for 2015 as we expect U.S. thermal hedge books to
disappoint with volumes at risk from both lower export demand and
MATS. In our view, the structural imbalances pressuring the U.S.
thermal coal market are set to worsen over the coming years as coal
retirements and the gas capacity build out are compounded by weak
international markets and new mine development in low cost basins
in ILB and NAPP. We see substantial FCF burn for most companies
through 2016 that is likely to result in further erosion of credit
metrics. With the exception of Consol, all U.S. coal equities in
our universe trade above 11x 2015 EV/EBITDA and at large negative
FCF yields. We believe the market must be applying cyclical
multiples to perceived trough earnings levels. In our view, the
issues facing the U.S. coal sector are structural and not cyclical
and believe future dislocation from carbon legislation and
potential disintermediation on the met side warrant valuation
multiples well below current levels, especially given excessive
debt leverage across the sector. To achieve a 7.0x 2015 EV/EBITDA
multiple, most equities require met prices near $170190/tonne.
Multiple Factors Driving Weaker Supply / Demand Dynamics in 2015
We believe fundamentals for the U.S. thermal coal market should
worsen into 2015 owing to demand loss associated with coal-to-gas
switching, sharply reduced export volumes, and most importantly the
implementation of MATS. We believe the market is underestimating
the magnitude of the negative impact on U.S. coal demand from MATS
and expect that PRB will be most negatively impacted; we see most
basins experiencing a net negative demand loss of 58% through 2016.
Furthermore, uncertainty with CO2 legislation is likely to drive
more retirement decisions over the coming years. U.S. thermal coal
supply / demand imbalances are expected to be compounded by
weakness in international markets. Seaborne indices recently
reached five-year lows and we expect markets to remain oversupplied
in the medium term, especially if China moves forward with
potential import restrictions for sulfur and ash, which would
impact almost 50% of all Australian thermal exports. Coking Coal
Market to Remain Weak Through 2016 China has seen a reversal in
trade flows for coking coal of ~30mt in 2014 (met, coke, and steel
equivalent), despite spot prices averaging ~$35/tonne lower than
2013. We believe Chinas domestic cost curve is shifting lower and
will result in lower-than-forecast met prices over the next several
years as we believe Chinese arbitrage sets spot price (which sets
benchmark). Our cost curve work suggests fair value in met today is
near $125/tonne. We also believe fixed costs in coal production are
much higher than realized and will result in uneconomic production
continuing globally. We expect China to step away from the seaborne
market at contract price levels above $135/tonne.
Global Markets Research 16 September 2014
See Appendix A-1 for analyst certification, important
disclosures and the status of non-US analysts.
-
Nomura | U.S. Thermal Coal Outlook 16 September 2014
2
Contents
Portfolio Manager Summary
.......................................................................................................................
3
U.S. Thermal Coal Outlook
.........................................................................................................................
4
Long Term U.S. Thermal Coal Outlook
...................................................................................................................
9
2015 Demand at Risk from MATS / Gas Backwardation
.......................................................................................
11
Plenty of Supply Side Options for U.S. Utilities
.....................................................................................................
14
PRB Tightness Fading Fast Spot Down to $10.85/ton
.......................................................................................
17
PRB Price Trends Back to Reality
......................................................................................................................
19
Seaborne Weakness Hurting Eastern Price Dynamic
...........................................................................................
21
Coal Retirement Clear and Present Danger
.......................................................................................................
26
Powder River Basin Most at Risk
..........................................................................................................................
29
Significant Spare Capacity Is Limiting Factor to Bull Thesis
.................................................................................
33
Contract Vintage Cycle Key for Medium-Term ASP
..............................................................................................
33
Understanding Cash Economics of the PRB
.........................................................................................................
35
What Happened to the PRB Growth Story?
..........................................................................................................
38
Switching Risks from Both Natural Gas and Illinois Basin
....................................................................................
40
PRB Export Terminals Are Critical to Long-Term Growth
.....................................................................................
43
The Fighting Illini ILB Production Set to Grow Meaningfully
..............................................................................
46
Outlook for CAPP Remains Weak
.........................................................................................................................
49
Met Outlook The China Syndrome
........................................................................................................
54
China Arbitrage Levels Set the Global Price
......................................................................................................
55
Why We Believe Cost Curves Dont Work Anymore
.............................................................................................
57
Production Cuts Might Not Matter?
........................................................................................................................
59
China Supply Outlet Be Careful What You Wish For
.........................................................................................
61
Company Sections
...................................................................................................................................
65
Alpha Natural Resources Neutral, $3 TP
...........................................................................................................
65
Arch Coal Reduce, $1.50 TP
..............................................................................................................................
66
Consol Energy Buy, $48 TP
...............................................................................................................................
67
Walter Energy Neutral, $4 TP
.............................................................................................................................
68
Peabody Energy Reduce, $11 TP
......................................................................................................................
69
Appendix A-1
............................................................................................................................................
71
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Nomura | U.S. Thermal Coal Outlook 16 September 2014
3
Portfolio Manager Summary We believe that the U.S. thermal coal
market faces accelerating structural overcapacity challenges over
the next several years as coal plant retirements and continued
coal-gas competition limit demand upside. U.S. thermal coal demand
is projected to decline significantly over the next several years
owing mainly to the impact of coal plant retirements. While U.S.
thermal demand should see a sizeable benefit from gas-to-coal
switching (near 20mt in 2014), we expect much of these gains to
reverse in 2015, given the recent weakening in the forward curve in
addition to widening basis differentials in the Mid-Atlantic and
Northeastern gas markets. Also, we see 3040mt of net demand at risk
in 2015 and 2016 as coal plants retire and more efficient, combined
cycle plants are brought online. Longer term, we see additional
retirement risks owing to uncertainty with regards to CO2
legislation and eventual implementation of new rules.
The ability for U.S. producers to offload more production to
international markets has been greatly impeded by the substantial
decline in seaborne thermal prices, where the forward curve remains
bearish through 2016. European coal prices have declined to their
lowest levels since 2010 owing to surplus markets in the Pacific
Basin and our analysis shows that not even low cost Illinois Basin
coal is economical enough to export at spot price levels. Traders
have noted that the significant increase in ILB production is now
starting to become a bigger factor influencing price levels in CAPP
and NAPP. We note that ILB production has increased ~30mt in the
past several years and is set to increase an additional 15mt
through the end of 2015 not an insignificant amount in a market
facing declining demand levels over the next two years.
The supply side of the equation for the thermal coal industry is
also challenged from structural overcapacity in the PRB and
short-run challenges with 2013 thermal export and crossover met
deals now coming back into the supply stream. In the PRB, we see
~5060mt of latent capacity that would be able to be brought back
online within a 34-month time frame and potentially 1015mt could be
ramped up within 12 months owing to increased shifts and increased
equipment utilization. Note that production in Wyoming totaled
~380mt in 2013 down from ~470mt in 2008 (and ~440mt in 2011)
suggesting there is 90mt of spare capacity. Illinois Basin
production has been growing share strongly as coal production
increased to 132mt in 2013 from 103mt in 2009.
Producer discipline has never been a strong suit of the U.S.
coal industry, in our view, and we dont expect the current period
of generally high financial stress to be any different. Alpha CEO
Kevin Crutchfield has noted that the incremental ton game from
19802000 didnt benefit the industry and historically there has
never been a strong market that the PRB hasnt produced itself out
of. Given the stretched balance sheets and typically high
incremental cash margins for the industry (especially in the PRB),
we would anticipate all producers to be aggressive to increase mine
production to drive unit cost leverage on higher volumes and
generate incremental cash flows as well.
As coal demand starts to be impacted by coal plant retirements
over the next several years, we expect producers will continue to
fight to maintain market share, a dynamic that could be partially
mitigated if the seaborne thermal forward curves were to strengthen
meaningfully, an event we view as unlikely. We do expect that
seaborne thermal prices will gradually recover as supply side
adjustments occur; however, we see this as more of a moderate
benefit to pricing in the East and not in the PRB. In general,
Eastern coal producers are much more leveraged to coking coal
relative to thermal. For the PRB, we see price gains limited by
arbitrage levels versus the ILB into the Midwest as ILB producers
aggressively expand their production base. Given highly leveraged
balance sheets and high incremental cash margins we see PRB
producers remaining aggressive in contracting to limit additional
market share losses.
Our analysis shows that price trends in the East are
significantly more correlated to API2 values versus the natural gas
price. Thus the steep selloff in seaborne values over the past year
has been a key issue in this regard. Weakness in the forward curve,
increased competition from ILB, MATS retirement impacts, and EPA
regulatory burdens all suggest weakness in CAPP and potentially
NAPP prices in 2015. Note that ANR recently issued a WARN notice
covering ~20% of its entire Central Appalachian thermal
portfolio.
-
Nomura | U.S. Thermal Coal Outlook 16 September 2014
4
U.S. Thermal Coal Outlook We believe that U.S. thermal coal
fundamentals are set to worsen into 2015 and expect that U.S.
coking coal ASPs are likely to move lower in 2015 owing to a
negative reset of domestic contracts as well as a continuation of
weak seaborne markets. We expect producers will see further volume
weakness which is likely to result in upward pressure on unit costs
unless entire operations are idled, similar to what ANR recently
announced. We believe the secular trends in coal continue to worsen
as U.S. thermal coal sees longer-term negative impacts from future
carbon legislation and the potential for disintermediation in the
seaborne coking coal markets.
We forecast high levels of cash burn in both 2015 and 2016 and,
as a result, forecast balance sheets becoming further impaired and
firms less likely to employ creative financing solutions going
forward. In the short run, we look for improved rail performance
and weakness in demand from the recent gas decline (and weak summer
burn) to result in above normal inventory build in the fall
shoulder season. Facing a difficult weather comp, US demand is
likely show negative growth rates this winter.
Recent EIA data supports this view with sub-bituminous
inventories increasing by 6.3mt over the past three months and
consumption growth showing a negative y/y move of 8% in May and 5%
in June. We believe that coal-to-gas switching and MATS demand side
impacts will be compounded by a combination of rising domestic
supply via new mine development in ILB and NAPP, sharply lower
thermal exports, and reduced crossover met tonnage in 2015. As
producers fight to baseload product into the more efficient
remaining coal plants, we see term contract bidding activity as
remaining very aggressive, which is evident in our price deck
below. Fig. 1: Nomura U.S. Coal Price Deck
*U.S. met prices are CFR port Hampton Roads. Source: SNL,
Bloomberg, Nomura estimates
Coal vs Gas Storage Rebalancing The 34th coldest winter on
record caused a
significant depletion of both gas and coal storage levels that
are well on their way to being rebuilt over the remainder of 2014.
Overall, we view gas storage as the more critical issue to the
market, but the recent strength in injections now suggests the
market will be adequately supplied entering winter. As a result,
the forward curve for 2015 has shifted down to $3.90/mmbtu, a level
at which combined cycle capacity competes very effectively with ILB
and Appalachian coals. The rail issues resulted in lost burn for
coal producers that cannot be made up and as production growth
improves in 2H-14, we see risks that coal stocks again grow to
above average levels.
U.S. Thermal Coal ($/st) 2012 2013 2014E 2015E 2016ECAPP CSX -
12,500 BTU 65 59 57 56 60NAPP - 13,000 BTU,
-
Nomura | U.S. Thermal Coal Outlook 16 September 2014
5
PRB vs Eastern Thermal To some degree, U.S. electricity
consumers were fortunate that coal stockpiles were high entering
winter allowing the substantial draw in stocks to have only
moderate impact on availability levels. The weak summer burn and
restocking activity has put current PRB days of burn at ~42 days
(which is moderately below normal), while bituminous stocks are at
49 days of burn (around the target levels of 50 days). However, we
note that EIA reported days of burn are calculated using a 3-month
forward burn forecast. We believe using historical consumption data
is most relevant and based on our calculation using trailing
36-month average consumption data, inventories are above normal at
53 days for sub-bituminous and 66 days for bit.
Rail and Logistics Challenges Being Met Since mid-March, we have
seen a significant recovery in rail car loadings as well as coal
production levels in the U.S., which are highly correlated to rail
car volumes. Both industries are responding well to recent
challenges, and we expect the system to be back to full capacity by
3Q-14. At a recent STB hearing, BNSF noted that it would be able to
increase deliveries by 7% in 2Q-4Q 2014 y/y following 1Q-14
performance of up 5% y/y. Union Pacific stated recently that it
will be back to normal by 3Q-14. Historically, the elimination of
supply side bottlenecks has resulted in price weakness in coal. In
our view, the recovery in the supply side and subsequent rebuild in
PRB stocks explains recent price weakness.
Structural Overcapacity in Thermal Set to Worsen We see the U.S.
thermal market as struggling with excess capacity over the next
decade as a combination of lower long-run gas price levels and a
significant amount of coal plant retirements structurally impair
demand levels. TVA noted recently that it forecast its coal burn to
decline from 48mt in 2013 to 24mt by 2018. We see future carbon
legislation as playing a key role in driving additional retirements
over the second half of this decade as significant investments are
made in renewable and gas capacity. Platts notes that 40GW of new
wind capacity is projected to be built in the U.S. in 20132020.
Today, we see at least ~5060mt of excess capacity in PRB and near
2030mt in Appalachia.
Backwardated Gas Curve and Basis Differentials Despite the rally
this winter, the Nymex forward gas curve remains near $4.00/mmbtu
from 201516. Also, basis differentials in the Northeast have
widened significantly suggesting very competitive dynamics for
Eastern coal producers. The inability for coal to compete in the
East will result in further CAPP closures and more intense
inter-basin competition, in our view, as evidenced by the large
cutbacks announced recently at ANR and PCX. Basis spreads have
widened to $0.300.60/mmbtu in key trading hubs in the East that
should result in very competitive dispatch costs for gas generation
relative to coal generation. We see NAPP and CAPP producers looking
to move more aggressively into traditional markets in the Midwest
negatively impacting ILB and PRB price levels.
Low Cost NAPP and ILB Supplies Entering the Market While CAPP
producers continue to shut down, new mines in Illinois Basin and
NAPP are projected to ramp up strongly over the next two years. We
project that 6mt of net new ILB capacity is brought online in 2014,
with an additional 89mt forecast to ramp up in 2015. We also see
increased thermal volumes in NAPP through both greenfield
development, as the BMX mine (3.5mt) ramps up in 2014, and
expansions at Murray Energy (34mt). Also, we project U.S. thermal
coal exports, which totaled 51mt last year, to decline by 8mt to
reach 43mt in 2014, also adding to domestic oversupply pressure.
Lastly, we estimate that 34mt of crossover met product is likely to
re-enter the U.S. thermal market in 2014.
Collapse in Seaborne Thermal Values Pressure U.S. Seaborne
thermal coal prices have fallen significantly in the past year and
now stand near their lowest levels in five years. The surplus in
the seaborne markets has resulted in increased pricing pressure in
the U.S. market from both arbitrage relationships as well as
thermal export contracts rolling off and coming back to add to U.S.
oversupply. Seaborne price weakness has had a major impact on
Eastern thermal prices, which in turn has created a limit on how
high PRB prices can move up. We are concerned that seaborne
oversupply problems will be compounded by potential restrictions in
China on imports of higher sulfur and ash products in addition to
weak demand levels recently. At Nomuras recent China Investor
Forum, Huaneng Power noted that productions cuts would unlikely
lead to a rebound in thermal prices, given that Chinas coal supply
should still exceed demand even if coal production dropped by 200mn
ton (~5%of the annual coal production).
-
Nomura | U.S. Thermal Coal Outlook 16 September 2014
6
Coal Plant Retirements to Hit in 2015 and 2016 We believe coal
plant retirements will have a sizeable impact on the industry over
the next several years and through the end of this decade. We
estimate that about ~35 GW will retire during 20142020, following
23GW shuttered from 2009 to 2013. We understand that operating
rates for plants set to retire was near 40% in 2013; however, many
were operating at much higher rates this winter and AEP noted that
all of its plants set to retire had been running above 90% capacity
factors. Our conversations with many utilities suggest that the
vast majority of the retirements will result in lost burn and not
be offset by rising capacity factors at remaining plants owing to
the fact that more gas capacity is expected to come online and most
of the remaining fleet is already operating at or near design
capacity levels.
2015 / 2016 Coal Contract Bidding Expected to Be Fiercely
Competitive Despite the inventory reduction over the past year we
believe contracting pressures remain severe. Cloud, Foresight, and
Alpha have all noted recently that bidding dynamics remain very
competitive for 2015 business, and we see the potential for buyside
disappointment to hedge book ASPs going forward, especially in the
PRB. We note that Cloud recently layered in 3mt of 2015 business
below $12/ton. We see the US thermal market facing a growing
structural surplus in 2015 as coal plants retire and new capacity
ramps in ILB and NAPP. Most of the new US capacity is longwall
based and we see these producers as being very aggressive in
base-loading this production. Also, with many coal producers
overleveraged, all will be highly motivated to run at high
utilization rates to keep costs down and benefit from high
incremental cash margins. Utilities Strategically Altering Targeted
Inventory Levels and Blends Utilities are working to improve
inventory management to create greater fuel source flexibility,
generate working capital sources, and thus carry less coal on a
days-of-burn basis. As a result, we think the drawdown in stock
levels in 2014 is likely not to result in sharp inventory restock
as some in the market have predicted. Nomura has developed a
forecasting model using EIA historical data for sub-bituminous and
bituminous coals as well as Wood Mackenzie consumption models. We
project that sub-bituminous days of burn will end 2014 at 53 days
(3 above normal) with bituminous at 67 (17 above normal). Note that
in April and May, sub-bituminous stocks increased by 8.7mt
following year-on-year demand declines of 10% and 5%,
respectively.
Contract Vintage Cycle Duration Gap Based on Nomura analysis, we
believe most coal producers have experienced continued weakness in
ASPs for each contract vintage over the past three years and, as a
result, blended ASPs continue to move lower for most companies.
Producers will need to cycle out of these vintages and into higher
priced vintages for aggregate ASPs to meaningfully improve, which
should require at least an 1824-month period of strong contract
price levels. It is important to note that in 2015 coal producers
are losing a relatively valuable 2011 vintage year and replacing it
with another weak period in 2014. Note that the two-year forward
curve for PRB8800 averaged near $16.00/ton during the year 2011. We
believe vintage shifts are not modeled accurately across the
sell-side and believe Nomura modeled ASPs for 2015 are well below
the Street partly from this variance (as well as a lower price
deck).
Volume Leverage vs Price Leverage For most producers today, unit
margins are relatively low for thermal coal owing to the recent
period of demand and price weakness. While longwall NAPP and ILB
producers enjoy relatively strong margin levels near ~$15-20/ton,
PRB producers are generating unit EBIT margins near $2.50/ton and
CAPP is close to breakeven across the basin. Maintaining adequate
volume levels to spread fixed costs across the operation is a key
economic requirement for a successful coal mine, and we are
concerned that as volume levels decline over the next several
years, it will become more difficult for producers to keep costs
down. Furthermore we see rising strip ratios as well as continued
pressure on environmental cost and regulations as well.
Balance Sheet Damage Negatively Influencing Production
Discipline Most U.S. coal producers have very over-levered balance
sheets and are likely to focus more on cash management than overall
margin levels in the short run. We expect most producers to
aggressively bid new contracts to try to maintain utilization
levels and benefit from high incremental cash margins. We believe
that weakness in the met market will continue through 2016 and
recent bearish data points in China suggest
-
Nomura | U.S. Thermal Coal Outlook 16 September 2014
7
benchmark contract prices could move moderately lower in 4Q-14
in our view. The negative FCF performance will further impair
balance sheets over the next two years and likely increase the
potential for dilutive equity raises, in our view. We believe asset
sale potential is limited in the current market environment and
most companies have already reduced capital spending levels to
below sustaining levels.
Equity Valuation Levels Are Stretched Most all US coal equities
(except CNX) appear very overvalued based on 2015 EBITDA forecasts,
with all firms trading above 11x EV/EBITDA and at negative FCF
yields. Given secular challenges in thermal, we see coking coal
becoming a more critical product for most companies and
historically more pure play coking coal equities have traded at
lower multiples relative to thermal producers. When factoring in
the strong potential for net debt levels to rise in 2015 and again
in 2016 for most producers, forward multiples become very dependent
on a powerful recovery in the coking coal markets to justify
current stock valuations.
Coking Coal Markets Remain Depressed Despite Production Cuts We
believe the fundamentals of the coking coal market are actually
getting worse as Australia continues to export coking coal at high
levels and China trade flow shifts have significantly impacted
trade balances and recent macro data in China has been bearish. We
lower our 2015 benchmark HCC view to $128/tonne (was $130/tonne)
and 2016 to $136/tonne (was $145/tonne). We believe the combined
effect from higher Chinese coke exports, higher steel exports, and
lower coking coal imports have cumulatively affected seaborne
demand by ~30mt. We note that Chinese apparent steel consumption is
up 0.4% YTD and exports are up 37% YTD, which have caused weakness
in steel output for key met consuming countries such as Japan and
Korea.
Seaborne Trade ex China is Weak Also - There has been very
little growth in key importing regions or countries with YTD import
growth from Japan of 0%, Korea up 2%, and Europe up 3%. We believe
the benchmark price is now effectively being set by the China spot
price, which in turn is driven by domestic factors within China.
China continues to lower its cost curve through volume growth and
localized subsidies. On the thermal side Chinese efforts to reduce
coal consumption and put import restrictions on higher sulfur and
ash thermal products is bearish in the medium term, especially for
Peabodys Australian thermal platform.
Reducing Coal Sector Estimates, Downgrading ACI and BTU to
Reduce We have revised our coal price deck to reflect our bearish
outlook for seaborne thermal, met, and PRB. Accordingly, we are
decreasing estimates for 2015 and 2016 for all coal companies under
our coverage. We downgrade Arch and Peabody to Reduce. We maintain
Neutral ratings on Alpha and Walter, but cut target prices to $3
(ANR) and $4 (WLT). Consol remains our only Buy-rated coal stock
with a target price of $48. Please see our detailed company
analysis at the end of this report, beginning page 65.
Fig. 2: Nomura U.S. Coal Valuation and Earnings Table $mm, as of
September 12, 2014
Source: Bloomberg, Nomura estimates
Company Ticker Rating Mkt Cap ($mn) Price Price Target
Upside/ Downside
FCF Yld 2014E
FCF Yld 2015E
Alpha Natural Resources ANR Neutral 762 3.44 3 -13% -52%
-24%Arch Coal ACI Reduce 626 2.95 2 -49% -64% -38%CONSOL Energy CNX
Buy 8,976 39.17 48 23% -4% -1%Peabody Energy BTU Reduce 3,868 14.44
11 -24% -5% -8%Walter Energy WLT Neutral 273 4.15 4 -4% -98%
-68%
2014E 2015E 2014E 2015E 2014E 2015E 2014E 2015EAlpha Natural
Resources (1.83) (2.72) 200 225 11% -22% 19.1x 17.0xArch Coal
(1.78) (1.45) 269 349 10% -16% 17.8x 13.7xCONSOL Energy 1.21 1.78
1,109 1,377 0% 1% 10.9x 8.8xPeabody Energy (1.19) (1.33) 734 798
-3% -27% 12.8x 11.7xWalter Energy (6.93) (4.05) 37 168 -27% -12%
77.1x 17.1x
EPS EBITDA EV/EBITDACompany NMR vs Street
-
Nomura | U.S. Thermal Coal Outlook 16 September 2014
8
Fig. 3: EV/EBITDA, 2015E
Source: FactSet, Nomura estimates
Fig. 4: FCF Yield, 2015E
Source: FactSet, Nomura estimates
Fig. 5: Debt to EBITDA, 2015E
Source: FactSet, Nomura estimates
Fig. 6: Liquidity to EBITDA, 2015E
Source: Company reports, Nomura estimates
Fig. 7: Met price needed to get 2015E EV/EBITDA to 7x $/tonne,
assumes thermal forecast and volume outlook unchanged
Source: FactSet, Nomura estimates
Fig. 8: FCF Yield at Current Spot Prices, 2015E
Source: FactSet, Nomura estimates
0.0x
2.0x
4.0x
6.0x
8.0x
10.0x
12.0x
14.0x
16.0x
18.0x
ANR ACI CNX BTU WLT -80%
-70%
-60%
-50%
-40%
-30%
-20%
-10%
0%ANR ACI CNX BTU WLT
0.0x
2.0x
4.0x
6.0x
8.0x
10.0x
12.0x
14.0x
16.0x
18.0x
ANR ACI CNX BTU WLT0.0x
2.0x
4.0x
6.0x
8.0x
10.0x
12.0x
ANR ACI CNX BTU WLT
$0
$50
$100
$150
$200
ANR ACI CNX BTU WLT -100%
-90%
-80%
-70%
-60%
-50%
-40%
-30%
-20%
-10%
0%ANR ACI CNX BTU WLT
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Nomura | U.S. Thermal Coal Outlook 16 September 2014
9
Long-Term U.S. Thermal Coal Outlook We believe that following a
strong start to 2014, coal fired generation is likely to be weaker
in 2H-14 owing primarily to coal-to-gas switching following the
sharp decline in the forward curve as well as a relatively cool
summer. While the historically cold winter created a perfect storm
of imbalances from both the supply and demand sides resulting in
sharply higher gas and coal prices in early 2014, we believe that
storage levels for both commodities will be back to normalized
levels by year-end. We believe it is important to note that
coal-to-gas switching affects primarily non-PRB basins, although a
certain degree of PRB volume that moves further east and is used
for blending purposes is also impacted. Note that Genscape data
shows U.S. coal generation up less than1% through July suggesting
downside risk to Street estimates.
We believe that U.S. thermal coal consumption is likely to
increase only ~2.5% for the year equating to incremental usage of
22mt, which we believe is below consensus. Importantly, we believe
that almost all of the increased coal burn required to balance the
market this year will be sourced from inventory reduction (16mt)
and a shift in the net trade balance (as U.S. thermal exports
decline ~7mt and imports increase ~2mt). New longwall production in
ILB and NAPP will also provide incremental supply to the market of
~10mt in 2014. Thus, we find the market moving back towards
oversupply. Fig. 9: Nomura U.S. Thermal Coal Supply / Demand Model
Mt
Source: EIA, Bloomberg, Nomura estimates
US Coal Supply 2008 2009 2010 2011 2012 2013 2014E 2015E
2016EProduction
Northern Appalachia 137 127 132 133 127 128 132 133 135 Central
Appalachia 228 192 187 183 148 128 131 120 110 Southern Appalachia
18 21 20 19 20 18 19 20 20 Illinois Basin 101 103 106 117 127 133
142 148 152 Pow der River Basin 510 469 487 480 438 430 430 425 425
Western Bituminous 57 50 45 47 45 40 40 41 41
Total Coal Production 1,214 1,110 1,084 1,096 1,016 996 1,018
1,012 1,008 YoY 20 (104) (26) 11 (79) (21) 22 (6) (4)
Thermal Imports 34 23 19 13 9 9 11 9 8 Total Exports 82 59 82
107 126 117 100 103 111
Metallurgical Coal 43 37 56 70 70 64 57 59 63 Thermal Coal 39 22
26 38 56 53 43 44 48
Net Export 47 36 62 94 117 108 89 94 103 Apparent Consumption
1,167 1,073 1,022 1,001 900 888 929 918 905
Changes in Inventory 12 40 (13) (0) 8 (39) (18) 3 (3) Thermal
Supply + Import 1,154 1,034 1,040 1,018 927 959 950 939 930
Coal Demand 2008 2009 2010 2011 2012 2013 2014E 2015E
2016EUtility Demand
Northeast 11 8 7 4 2 4 6 5 4 RFC Region 330 291 303 282 243 253
265 253 250 Southeast 318 275 295 276 239 244 252 243 235 Southw
est 146 137 144 152 134 140 143 145 140 Midw est 110 104 106 103 95
99 100 97 100 West 126 118 123 117 112 120 115 110 108 Other 1 1 1
1 1 1 2 2 2
Total Electrical Demand 1,042 935 980 935 827 862 883 855 839
YoY Change in tons (4) (108) 45 (45) (108) 35 21 (28) (16) YoY %
Change 0% -10% 5% -5% -12% 4% 2% -3% -2% Subbituminous 539 492 500
483 434 447 459 445 435 Bitmuminous 440 386 419 386 330 347 365 350
345 Lignite 63 57 60 64 62 60 59 60 59
Total Non-Electricity 80 64 74 71 67 68 68 69 68 Total U.S. Coal
Demand 1,123 999 1,053 1,006 894 930 951 924 907 Total Thermal +
Export 1,139 1,005 1,058 1,022 928 961 972 944 932
-
Nomura | U.S. Thermal Coal Outlook 16 September 2014
10
Genscape Data Confirms Weak Summer Start, PRB Softness The
overall U.S. data from Genscape through June shows coal generation
is up only 1% YTD; however, Western markets are actually down ~7%
(albeit at small usage levels) compared to the 3% rise in the East.
The Genscape data shows that coal growth rates slowed significantly
in the shoulder season given the YTD figure of up only 1%. Note
that the West accounts for only 12% of total U.S. coal generation.
We believe the U.S. thermal coal market and the natural gas market
will be intertwined for the foreseeable future, with weather and
storage shifts the main drivers of pricing over the next few years
given the declining demand for coal and continued production growth
of associated gas and shale gas. With the forward gas curve now
below $4.00/mmbtu over the rest of 2014, we expect to see depressed
demand levels, barring weather-driven upside.
We believe there is a growing risk that coal stockpiles increase
further as contracted volumes are made up for in the back half of
the year, within a backdrop of weaker coal-to-gas-induced demand
levels. Note that the gas price weakness is being exacerbated in
certain markets by wider basis differentials in addition to new
longwall development by Foresight and White Oak. In short,
competition appears to be growing in the market and supply / demand
imbalances should worsen into 2015 as MATS regulations result in
coal plants coming offline.
Fig. 10: U.S. Coal Usage in Electricity Generation YTD burn data
through July
Source: Genscape, Nomura research
Fig. 11: U.S. Coal Usage in Electricity Generation YTD burn data
through July
Source: Genscape, Nomura research
Fig. 12: YoY Change in U.S. Coal Fired Generation YoY % Chg in
U.S. Coal Based Electricity Generation
Source: EIA, Nomura research
Fig. 13: Total U.S. Coal Fired Electricity Generation Million mw
hrs
Source: EIA, Nomura research
-8%
-6%
-4%
-2%
0%
2%
4%
National East West
YTD Last Year % ChgNational 515.3 511.6 1%
East 439.5 428.2 3%
West 62.3 66.9 -7%
E.N. Central 121.4 112.8 8%
W.N. Central 78.4 77.1 2%
E.S. Central 54.7 54.3 1%
W.S. Central 87.5 90.4 -3%
Mid-Atlantic 23.8 22.9 4%
S. Atlantic 79.3 65.7 21%
Mountain 59.6 64.0 -7%
-16%
-12%
-8%
-4%
0%
4%
8%
2006 2007 2008 2009 2010 2011 2012 2013 2014E 2015E
1.25
1.50
1.75
2.00
2.25
2006 2007 2008 2009 2010 2011 2012 2013 2014E 2015E
-
Nomura | U.S. Thermal Coal Outlook 16 September 2014
11
2015 Demand at Risk from MATS / Gas Backwardation Despite the
positive set up for 2014, we see significant demand side risks
facing the industry in 2015 as gas storage normalizes (2015 gas
curve is backwardated by ~$0.20/mmbtu at $4.20/mmbtu) and a
significant amount of coal fired plants are retired, while at the
same time, new gas generation comes online (greenfield development
and retrofits). Based on the lower forecast gas price in 2015, we
estimate about 1015mt of reverse switching back to gas is likely to
occur. Given coal inventories are now at more normal levels, we
dont see a scenario that would cause a substantial rebuild
opportunity for producers in the second half of 2014, as Eastern
markets remain well supplied and the majority of PRB burning power
plants are likely operating within targeted bands. This was evident
from recent conference call commentary.
Reverse Switching to Add ~30mt to 2014 Demand Based on our
dispatch model, we estimate that PRB should see incremental demand
of only 13mt in 2014 (mainly from PRB tied to Eastern markets via
blends) compared to IB of 9mt, CAPP of 2mt, and NAPP of 7mt. Since
2008, our model shows that ~110mt of U.S. thermal coal will have
been displaced by gas-fired generation over the forecast period
through 2014. Note that this data compares to an actual loss of
183mt when measured again the EIA reported electric power
consumption figure of 1,041mt in 2008 and 858mt in 2013. We
forecast thermal coal demand of 883mt in 2014, which would bring
the loss since 2008 to 15mt and thus our dispatch model would
suggest that ~70% of the demand loss over the forecast period is
attributable to coal-to-gas switching. We estimate the remainder of
the demand loss has been driven by growth in renewable energy and
weakness in industrial demand.
Fig. 14: Coal-to-gas Displacement by Region Mt
Source: Wood Mackenzie, Nomura estimates.
Fig. 15: Coal-to-gas Switching by Basin YoY chg
Source: Wood Mackenzie, Nomura estimates.
The historically cold winter coupled with surging natural gas
prices has resulted in very strong growth in coal fired electricity
generation at the start of the year, which has since faded
strongly. Genscape data below shows that U.S. coal generation is up
only 0.7% through July, while EIA data showed JanMay rising 5%. We
estimate that the cold winter is likely to benefit coal usage alone
by ~5mt, and we see gas switching providing another ~20mt of demand
growth in 2014, benefiting Eastern basins primarily. For 2014, we
expect that the vast majority of demand growth will be in areas
where incremental gas to coal switching is most prevalent, and for
this reason, we see PRB demand growth trailing overall usage growth
in 2014 as PRB plants have been well in the money since the start
of 2013. We note that PRB prices are today trading back near
$11.00/ton.
-10
-5
0
5
10
15
Jan-09 Jan-10 Jan-11 Jan-12 Jan-13 Jan-14
Mln
Sho
rt T
on
West (WECC)
Southeast (SERC + FRCC)RFC Region
Northeast (NPCC)
29
(14) (14)
13
(6) (6)
48
(33)(8)
9
(7)
(2)
(80)
(60)
(40)
(20)
-
20
40
60
80
100
120
2012 2013E 2014E
Mt
IB
PRB
NAPP
CAPP
-
Nomura | U.S. Thermal Coal Outlook 16 September 2014
12
This has been evident by very weak sub-bit consumption data over
the past several months and note that EIA data shows sub-bit demand
declining by 10% y/y in April and 8% y/y in May. EIA data shows
sub-bit demand has actually declined y/y by 0.5%. By contrast,
bituminous coal usage, which is heavily influenced by coal-to-gas
switching, has increased 12.5% through May. As a result, coal
inventories have fallen significantly more in the East, although
they remain above normal levels. One of the reasons for the
weakness in sub-bit usage was related to poor rail service that
resulted in lost burn as utilities were forced to conserve
stockpiles and burn alternative fuels. Fig. 16: PRB Spot Prices
Have Declined 20% From April High of $13.60/ton PRB 8800 spot
($/ton) Natural gas spot ($/mmbtu)
Source: Bloomberg, Nomura research
Fig. 17: U.S. Bituminous Demand Growth Y/Y EIA data growth rates
starting to moderate
Source: EIA, Nomura research
Fig. 18: U.S. Sub-bituminous Demand Growth Y/Y EIA data set very
weak April and May
Source: EIA, Nomura research
In many respects the U.S. power industry was fortunate that
enough coal stockpiles were available this past winter to meet the
high demand loads and limit even further upward pressure in the gas
market. This dynamic in the coal industry stands in stark contrast
to the gas market where storage levels are well below normal for
this time of year. Given the more critical storage predicament in
the gas market, it is not surprising that gas prices earlier this
year increased to a level at which higher cost coals will dispatch
as market forces drive more gas into storage and away from utility
burn. We find it unlikely that both coal and gas markets will exit
this year at well-below-average levels of storage, especially given
coal is at target levels today. The figure below shows that Napp
and Capp prices today are equivalent to $3.804.00/mmbtu gas.
2.0
2.5
3.0
3.5
4.0
4.5
5.0
5.5
6.0
6.0
7.0
8.0
9.0
10.0
11.0
12.0
13.0
14.0
Jun-12 Oct-12 Feb-13 Jun-13 Oct-13 Feb-14 Jun-14
PRB 8800 Prices
Natural Gas Price
-15%-10%-5%0%5%
10%15%20%25%30%
Jan-
13Fe
b-13
Mar
-13
Apr
-13
May
-13
Jun-
13Ju
l-13
Aug
-13
Sep
-13
Oct
-13
Nov
-13
Dec
-13
Jan-
14Fe
b-14
Mar
-14
Apr
-14
May
-14
-15%
-10%
-5%
0%
5%
10%
15%
20%
25%
Jan-
13Fe
b-13
Mar
-13
Apr
-13
May
-13
Jun-
13Ju
l-13
Aug
-13
Sep
-13
Oct
-13
Nov
-13
Dec
-13
Jan-
14Fe
b-14
Mar
-14
Apr
-14
May
-14
-
Nomura | U.S. Thermal Coal Outlook 16 September 2014
13
Fig. 19: Parity Price Levels Near $3.40$4.40 Across All U.S.
Coal Basins Except CAPP
*Delivered to a Midwestern utility. Source: EIA, Bloomberg.
Nomura estimates
Fig. 20: Combined Cycle Generation Now Competitive with NYMEX
Capp Cost comparison on a delivered basis to PJM/RFC, $/MWh
Source: Bloomberg, Nomura research
We believe U.S. thermal coal supply growth could have
potentially reached 50mt in 2014 had demand trends remained strong
throughout the summer. At the end of 1Q, our demand model had
projected ~50mt of consumption growth for U.S. thermal coal in
2014, but we have since cut that demand forecast by more than 50%
to 24mt. We believe the majority of the incremental demand growth
in 2014 will be satisfied by inventory liquidation and a diversion
of exports back towards domestic customers. The relatively cool
summer resulted in weak burn levels relative to 2013 with Genscape
data showing weekly coal burn was below the year-ago levels for
nearly every week from April to July.
NAPP CAPP IB PRB Uinta SC-Gas CC-GasAvg BTU/lb 13000 12500 11000
8800 11500
Spot price ($/ton for coal) 57.00 60.00 41.00 11.00 34.00Spot
price ($/mmBTU) 2.19 2.40 1.86 0.63 1.48 3.80 3.80
Transportation costs ($/ton)* 14 11 8 25 22
Transportation / basis ($/mmBTU) 0.54 0.44 0.36 1.42 0.96 0.20
0.20
Spot cost of delivered coal ($/ton) 71 71 49 36 56
Spot coal delivered ($/mmBTU) 2.73 2.84 2.23 2.05 2.43 4.00
4.00
Plant heat rate 10500 10500 10500 10500 10500 11000 7500
Delivered cost spot basis ($/MWh) 28.7 29.8 23.4 21.5 25.6 44.0
30.0
Plant O&M costs ($/MWh) 4.0 4.0 4.0 4.5 4.0 2.0 2.5
Total Cost ($/MWh) 32.7 33.8 27.4 26.0 29.6 46.0 32.5
Gas plant heat rate 7500 7500 7500 7500 7500 11000 7500
Gas Plant Variable O&M ($/MWh) 2.5 2.5 2.5 2.5 2.5 2.0
2.5
Gas transportation / basis ($/MWh) 1.5 1.5 1.5 1.5 1.5 2.2
1.5
Implied Gas Partiy Price by Basin 3.82 3.98 3.12 2.93 3.41
10
20
30
40
50
60
Aug-11 Jan-12 Jun-12 Nov-12 Apr-13 Sep-13 Feb-14 Jul-14
$/M
Wh
PRB 8800 Henry Hub Spot Eastern Rail Big Sandy
-
Nomura | U.S. Thermal Coal Outlook 16 September 2014
14
Plenty of Supply Side Options for U.S. Utilities We believe RFP
activity will be relatively weak over the remainder of the year as
coal inventories are likely to build again to above-normal levels
following a weak summer burn and improved rail performance that
should enable most coal producers to catch up on volume commitments
by early 2015. While some utilities did run down coal stockpiles to
uncomfortably low levels this summer, we believe that supply has
been more than adequate to ensure reliable power over the summer.
Our conversations with traders suggest that most large RFPs over
the past quarter were very oversubscribed and in many instances
utilities were able to source imported thermal coal from Colombia
at very attractive price levels.
Our contacts at Coal and Energy Daily noted that both NAPP and
ILB producers were very aggressive into recent RFPs in order to
shore up open positions for 2014 in addition to realign the sales
book towards scrubbed plants. The significant destocking of
inventory coupled with ILB / Colombia thermal coal supply side
response has provided a sizeable cushion to the demand shock which
occurred this past winter in addition to transportation shortfalls.
Fig. 21: 2014 U.S. Thermal Drivers Mt
Source: Nomura estimates.
Fig. 22: 2014 Supply Growth Waterfall Destocking and Trade
Balance Critical YoY Net Change to U.S. Thermal Supply
Source: Nomura estimates.
Despite structural overcapacity of U.S. thermal coal in the
U.S., we project significant new capacity coming online in 2014
owing to new mine development in both NAPP and ILB, which together
are set to increase production by 11mt based on our estimates. This
new capacity is for the most part very low cost longwall capacity
from Foresight, Murray Energy, Arch Coal, as well as Consol. Keep
in mind that many CAPP producers also have spare capacity as the
supply base has yet to fully rationalize for both domestic
displacement as well as exports redirected towards U.S. thermal
coal customers. Also note that Eastern bituminous inventories still
remain above 50 days, despite 13mt of inventory depletion so far in
2014.
The 2014 weather-driven demand surge and transportation
bottlenecks have caused a rapid reduction of coal inventories that
had been well above normal entering the year. This dynamic has been
a key gating factor for not putting more stress on the supply
chain, and we estimate that ~70% of the incremental coal burn for
2014 will be satisfied from inventories being reduced to normal
levels as well as trade flow reversals from higher imports and
reduced exports (down 25% YTD). It is important to note that
thermal inventories have already been reduced by 13mt through May
and are likely to see a total reduction for the year near ~10mt
owing to partial builds in 2H-14.
Supply Side ResponseInventory 16.0Thermal Exports 5.0Thermal
Imports 2.0Crossover Met 3.0PRB Prod 2.0ILB Prod 6.0Appalachia Cuts
-10.0Total 24.0
Demand Side ResponsePRB 6.0CAPP/NAPP 11.0ILB 5.0Other 2.0Total
24.0
0
5
10
15
20
25
30
35
40
Inventory Thermal Exports
Thermal Imports
Crossover Met
PRB Prod ILB Prod Appalachia Cuts
-
Nomura | U.S. Thermal Coal Outlook 16 September 2014
15
Fig. 23: U.S. Thermal Coal Stocks in Days of Burn Back to Normal
but Risks Grow into 2015 as Coal Plants Restock Days of burn using
trailing 24mo usage data.
Source: EIA.
U.S. Basis Risks Complicate Switching Dynamics in East Over the
next several years, we see coal-to-gas switching as the key demand
driver for U.S. thermal coal, with coal retirements also a very
critical factor. Dispatch economics ultimately will determine how
much coal generation is used each year, and based on the forward
gas curve through 2017, we see very challenging economics for CAPP
generation and as well as very competitive interplay with ILB and
NAPP. NAPP especially has near-term challenges given wide basis
differentials. We recently hosted meetings with Consol in
Pittsburgh and management noted that basis is likely to average
near $0.50/mmbtu in the PJM region, which effectively reduces the
parity level by that amount. We see coal-to-gas switching levels as
key balancing points for the U.S. thermal coal market over the next
several years, setting reliable floors and caps for both
markets.
Fig. 24: Basis Risks Suggest Coal-to-gas Displacement in East
Should Remain Overhand on Prices Regional gas basis in mmbtu
Source: Bloomberg, Nomura research
30
40
50
60
70
80
90
Jan-89 Jan-91 Jan-93 Jan-95 Jan-97 Jan-99 Jan-01 Jan-03 Jan-05
Jan-07 Jan-09 Jan-11 Jan-13
Total Days of Burn (2 year trailing burn) Target Upper Band - 55
Days
Target Lower Band - 45 Days Linear (Target Lower Band - 45
Days)
-1.20
-1.00
-0.80
-0.60
-0.40
-0.20
0.00
0.20
0.40
0.60
0.80
2003-2010 2010 2011 2012 2013 2014E 2015E
Spot
Bas
is v
s HH
($/M
MBt
u)
M3 TCO Dominion
-
Nomura | U.S. Thermal Coal Outlook 16 September 2014
16
Storage Levels Could Build Again to Uncomfortable Levels We
believe that the strong inventory build for sub-bituminous stocks
in April and May (coupled with weak burn data through July) suggest
that PRB stocks are at risk of ending the year at above-normal
levels again. Anecdotal evidence suggests the above-trend build in
inventories during the spring shoulder season was a function of
forced burn of alternative fuels to conserve coal and thus that
burn is lost forever. Compounding the rail issue has been the very
mild summer that resulted in negative growth rates through July per
Genscape. Coal and Energy Daily noted recently that a Midwest
utility that gained 250,000 tons of burn in the first half lost
150,000 in July alone and was on pace to lose another 100,000 tons
in August.
On a days-of-burn basis through June, sub-bituminous stock
levels were at 42, based on the data set we aggregate from the EIA.
Note that the June EVA data set showed PRB inventories at 53 days
of burn. Quarterly results from the major utilities coupled with
our own channel checks in the coal trade channel suggest that
inventories are generally at normal levels for this time of the
year, as rail performance has improved and a mild summer has
reduced burn. One of the key themes from the Coaltrans conference
this year was the desire from many utilities to operate with lower
inventories to better manage switching dynamics with the gas
market.
EVA notes that regulated utilities target 3540 days of burn
(consistent with AEP and SO comments this quarter), while merchant
plants target closer to 2530 days. Note that regulated utilities
bear the risk of disallowances if they run out of coal. Fig. 25:
PRB Days of Burn by Region EIA days of burn through June
Source: EIA, Nomura research
Fig. 26: Bituminous Coal Days of Burn by Region EIA days of burn
through June
Source: EIA, Nomura research
Fig. 27: Detailed EIA Inventory Breakdown for June 2014 Mt
Source: EIA, Nomura research
20
30
40
50
60
70
80
90
100
Jan-09 Jan-10 Jan-11 Jan-12 Jan-13 Jan-14
Midwest South West USA20
40
60
80
100
120
140
Jan-09 Jan-10 Jan-11 Jan-12 Jan-13 Jan-14
Midwest South West USA
Zone Coal Stocks (1000 tons)
Days of Burn
Stocks (1000 tons)
Days of Burn
% Change of Stocks
Stocks (1000 tons)
Days of Burn
% Change
Northeast Bituminous 5,062 41 7,208 52 -29.80% 4,596 39
10%Northeast Subbituminous 359 27 470 26 -23.60% 410 38 -12%South
Bituminous 30,783 48 48,508 77 -36.50% 32,298 51 -5%South
Subbituminous 4,631 39 5,147 44 -10.00% 4,803 42 -4%Midwest
Bituminous 13,596 47 15,639 54 -13.10% 13,754 50 -1%Midwest
Subbituminous 29,375 40 40,249 54 -27.00% 31,365 44 -6%West
Bituminous 5,175 78 6,725 104 -23.00% 5,343 84 -3%West
Subbituminous 21,615 46 30,819 65 -29.90% 22,651 51 -5%USA
Bituminous 54,616 49 78,080 69 -30.10% 55,990 51 -3%USA
Subbituminous 55,980 42 76,684 57 -27.00% 59,230 46 -6%
May-14Jun-14 Jun-13
-
Nomura | U.S. Thermal Coal Outlook 16 September 2014
17
PRB Tightness Fading Fast Spot Down to $10.85/ton We believe the
inventory dynamic will be a key determinant of utility buying
behavior over the remainder of 2014 and into 2015. Our model
suggests that PRB consumption will increase only 1% in 2014 (or
4mt) as PRB sees less gas-to-coal switching benefits given most PRB
plants have been economic versus gas for the past 15 months. We see
demand growth for PRB in 2014 coming mainly from weather-driven
baseload growth as well as some switching benefits for PRB that
moves further East for blending purposes (~60mt exposure). Our
model below shows all the key variables impacting the market from
the demand and supply side. What is interesting is that YTD through
April, rail car loadings for BN and UP combined are up 4%, despite
the slow start to the year.
Given the high stock levels entering 2014, utilities will be
able to satisfy the majority of the demand increase from inventory
drawdown, and EIA data through May show sub-bituminous inventories
have been depleted by 3mt, to stand at 67mt. While stock levels at
some utilities went lower than predicted this winter mainly from
rail bottlenecks, overall inventories are at reasonable levels and
should build further in 2H of 2014.
Our S/D model for PRB suggests that days of burn will move lower
by a few days this summer, but is very likely to be at or above
normal levels by year end. It is important to note that PRB
producers have significant exposure to coal plants slated to retire
next year, and we believe the reported EIA days of burn data is
partially skewed from those plants planning to burn down inventory
to zero by mid-2015 or 2016.
The next few months of EIA consumption and inventory data will
be very telling in terms of evaluating the ability for the coal
supply chain to respond and also the degree to which a mild summer
has offset the demand side benefits from a strong winter burn. The
Genscape data implies negative demand growth for both June and July
near 6-7%.
Fig. 28: Nomura PRB (Sub-bituminous) Supply and Demand Model
Mt
Source: Bloomberg, EIA, Nomura estimates.
2Q-13 3Q-13 4Q-13 1Q-14 Apr-14 May-14 Jun-14 2Q-14 % Q/Q YTD %
Chg 2014EEIA Sub-bit Consumption 103 123 111 114 29 31 36 95 -68%
-1% 451EIA Sub-bit Inventory 85 76 73 58 63 67 65 65 11% -8% 65Days
of Burn TTM 68 61 59 49 51 55 53 53 9% -22% 53EIA Days of Burn (3
yr) 66 60 58 52 57 51 45 51 -13% -20% 53
EIA PRB Production (ar) 406 469 420 423 418 426 412 419 -1% -1%
460BNSF / UP Loadings (ar) 401 463 425 432 413 422 405 413 -4% 4%
na
Actual EIA Chg (q/q) -4 -9 -3 -15 4 4 -2 6NMR Inventory Est Chg
(q/q) -4 -8 -3 -11 3 6 0 9
PRB 8800 ($/t) 12.20 11.27 11.84 12.63 13.10 13.33PRB 8400 ($/t)
9.82 9.82 9.75 9.98 10.50 10.23 8400 Disc -20% -13% -18% -21% -20%
-23%
2009 2010 2011 2012 2013 2014E 2015E 2016E % Chg 14 % Chg 15EIA
Sub-bit Consumption 491 499 486 434 447 451 438 429 1% -3%EIA
Sub-bit Inventory (YE) 92 81 82 86 73 65 60 61 -11% -8% Inventory
Build / (Draw) -26 -11 1 4 -13 -8 -5 1
Days of Burn TTM 71 62 58 78 65 53 46 47 -19% -13%EIA Days of
Burn (3 yr) 73 60 55 73 63 53 47 48 -15% -12% Days Above / (Below)
Tgt 28 15 10 28 18 8 2 3
EIA PRB Production 469 487 480 436 433 435 435 425 0% 0%MSHA PRB
Production 455 468 462 419 408 417 418 406 2% 0%
PRB 8800 ($/ton) 8.95 12.82 13.36 8.76 10.41 12.00 12.75 13.00
15% 6%PRB 8400 ($/ton) 7.37 10.03 11.03 7.07 9.48 10.00 10.50 10.60
5% 5% 8400 Disc -18% -22% -17% -19% -9% -17% -18% -18%
-
Nomura | U.S. Thermal Coal Outlook 16 September 2014
18
PRB Production Remains Weak, despite Rail Improvements PRB
production has trailed behind demand growth in 2014, with
production increasing 0% YTD off an easy comparison period owing
mainly to transportation problems this past winter. However, the
rail car data for both BNSF and UP is now positive year on year and
PRB production has rebounded over the past several weeks to ~430mt,
although still below the year to date run rate of 421mt. Keep in
mind that in the year ago third quarter, PRB production peaked at
469mt. At an STB hearing in 2Q, BNSF, which accounts for ~63% of
PRB shipments, projected it would be able to deliver 23.5mt, 25mt,
and 24mt, respectively, over the remaining three quarters of 2014,
which would equate to a 7% increase over 2013. This highlights our
view that the PRB has significant spare capacity that can come back
online relatively quickly, much of that in the 8400 market.
Spreads have widened significantly for PRB8400 as those prices
have trailed the recovery in the 8800 product by a wide margin.
Note that PRB 8800 prices are up ~30% since the 2013 spot price
low, compared to the PRB 8400 recovery of 7%. We expect the glut of
spare capacity in 8400 PRB coal as well as the substantial discount
relative to 8800 PRB will act as a significant overhang on prices
going forward. Fig. 29: PRB Rail Car Loading Data YTD data through
July 11
Source: Bloomberg, Nomura research
Fig. 30: EIA Sub-bituminous Inventory Dynamics Summer Draw Avg
is 14mt Mt
Source: EIA, Nomura research
Fig. 31: 8400 Spreads Have Widened Significantly % Disc 8400 PRB
vs 8800
Source: SNL, Nomura research
Fig. 32: Reason for CLD Shutdown Decision at Cordero Rojo$/ton
PRB 8400 spot price
Source: SNL, Nomura research
-6%
-4%
-2%
0%
2%
4%
6%
2Q Q/Q %chg YTD %chg
UP BNSFDate 2008 2009 2010 2011 2012 2013 2014 AvgJan (3,257)
(2,198) (5,555) (4,804) 6,112 (3,126) (5,172) (2,571)Feb (1,377)
1,202 (3,172) (3,010) 3,199 (1,538) (5,950) (1,521)Mar 3,266 2,229
2,293 3,236 5,664 (2,766) (524) 1,914Apr 4,142 3,620 3,531 4,563
3,672 (1,166) 4,238 3,229May 2,388 3,570 1,969 1,199 95 1,183 4,447
2,122Jun (4,524) (876) (4,215) (4,500) (3,462) (3,615) (2,414)
(3,372)Jul (2,782) (872) (5,366) (9,081) (5,132) (4,515) (4,625)Aug
(560) (1,321) (4,852) (6,743) (2,594) (2,348) (3,070)Sep 3,558
1,638 1,825 3,029 1,759 (976) 1,806Oct 3,436 48 6,086 4,962 692
(705) 2,420Nov 4,362 1,940 3,888 5,536 761 1,376 2,977Dec (1,552)
(7,746) (1,965) 3,849 (2,084) (5,641) (2,523)
Avg. 5 Yr Max Year 5 Yr Min YearWinter Draw (6,615) 13,160 11/12
(16,763) 13/14Spring Build 7,264 9,796 2008 (2,749) 2013Summer Draw
(11,067) (3,069) 2009 (20,324) 2011Fall Build 7,203 13,527 2011
(305) 2013
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Nomura | U.S. Thermal Coal Outlook 16 September 2014
19
PRB Price Trends Back to Reality The price trends in 1H 2014 for
PRB coals suggested a sharp divergence in PRB fundamentals relative
to the rest of the U.S. coal market in addition to the global
market, as PRB prices staged a 20% rally while seaborne prices
collapsed and U.S. Appalachian coals saw a declining trend. In our
research, we wrote how this divergence was primarily a function of
higher relative scarcity in the PRB owing to severe transportation
bottlenecks limiting the ability of utilities to restock as well as
an inventory position that was and remains significantly lower than
Eastern coals on a days of burn basis (see Where Has 90mt of PRB
Supply Gone?). Also, keep in mind that the recovery in PRB prices,
while impressive, had only allowed PRB prices to recover to a level
to allow for cash generative margins on a C3 basis and thus did not
reflect a true deficit condition that would allow for cash
generation.
After experiencing weakness in demand from April through June
(cumulative consumption declined 8% yoy) and improved rail service
coupled with utilities procuring imported material or limiting coal
burn to preserve stocks, this temporary deficit condition passed
without lingering impact to scarcity levels and PRB prices have
declined back down to $10.85/ton. This marks the lowest price level
since late 2013. Note that CLD recently priced PRB coal for 2015
below $12.00/ton, which suggests to us that the physical markets
did not benefit from the spot price strength in 1H 2014. Given PRB
is a captive basin, we believe it will be very difficult for PRB
prices to rally without a meaningful rally in the East, which would
only occur if gas prices stay above $4.75/mmbtu for a sustained
period of time.
Historically, the PRB price has responded to tightening
conditions in the East and, as Eastern prices were bid up, the PRB
would then typically start to rise on a lagged basis as utilities
sought more PRB coals to backfill. Most of the large upside moves
in the PRB market over the past decade have been driven by extreme
weather or transportation related bottlenecks that created
short-term tightness in the market.
We note that over the past decade, there have been very few
meaningful price rallies in the PRB that were sustained beyond
several quarters, as often the production response had been
significant (as shown in the figure below).
Fig. 33: PRB Production Responds to Price Signals within 36
Months PRB prices $/ton (lhs) Annualized PRB production (mmst)
Source: SNL, EIA, Nomura research
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PRB Annualized Production Rate (mmst)
Higher production = higher demand. PRB production has lagged
owing to rail challenges (current rate is ~415mtpa) which are slow
to resolve resulting in lost burn. Production is set to increase in
2H allowing inventories to normalize and driving further price
weakness in our view. Note that PRB produced at 465mt rate from
Aug-Oct of 2013 before weather issues.
http://intranet.nomuranow.com/research/globalresearchportal/getpub.aspx?pid=684702&appname=GRP&cid=ZGcwb3U2LzZpSDg90
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Nomura | U.S. Thermal Coal Outlook 16 September 2014
20
Gas Markets Also Look Range-bound in Short Run We note that PRB
prices are highly correlated to gas in the short run and the
backwardated gas curve suggests potential correlation risk in 2015.
Given superior dispatch economics versus gas (in most regions), we
believe PRBs value to a utility is based more on a parity price
level with other domestic coal basins, given very low amounts of
PRB are exported annually (less than 10mt). As a result, we believe
the weakness in the seaborne market coupled with aggressive
expansion plans from both ILB (Foresight, White Oak, Peabody) and
NAPP producers (mainly Murray) is likely to create a very
competitive market in the key Midwestern markets where PRB has a
strong position in. We believe PRB producers are very aware of the
incremental production forecast from ILB and will seek to maintain
market share by bidding aggressively into plants unaffected by MATS
(which should negatively impact PRB demand levels).
Coal-to-gas economics coupled with cheaper ILB coals coming onto
the market are likely to result in gas prices remaining below
$4.00/mmbtu until winter. Another factor limiting the ability for
Eastern coal prices is all the trapped gas in the Marcellus region
that has resulted in large negative basis for the PJM market and
caused many coal plants to move above gas on the merit order. Note
that Tetco M3 (key pipeline for PJM) is trading in a range of
$12/mmbtu below Henry Hub in the forward market (excluding winter
months). Fig. 34: PRB Price Cycles Well Correlated with Natural Gas
Price Spikes PRB 8800 spot ($/ton) and Natural gas spot
($/mmbtu)
Source: Bloomberg, Nomura research
Furthermore, PRB prices tend to move late relative to Eastern
thermal coals as (often from linkage to improvements in seaborne
prices). We see Eastern thermal prices range bound over the next
several years owing to weak natural gas prices and competitive
threats from ILB and NAPP. Unfortunately the steep decline in
seaborne prices for API 2 and Newcastle resulted in weak price
trends in Eastern coal markets and limited the upside normally seen
on a lagged basis in the PRB.
We note that Capp Nymex prices are trading at $58/ton per ton
for 1Q-15 and $59/ton for calendar 2015, which compares to the
current spot price of $57/ton, suggesting little to no upside for
2015. Nymex Capp prices have fallen by $7/ton over the past three
months as supply availability has improved.
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Nomura | U.S. Thermal Coal Outlook 16 September 2014
21
Seaborne Weakness Hurting Eastern Price Dynamic We believe
seaborne thermal markets will remain in surplus through 2015 and
see cost curve pressure from currency weakness in key export
countries, such as Indonesia and Australia. We believe weak API2
levels are the major reason why CAPP/NAPP prices have
underperformed relative to the moves seen in PRB and gas over the
past several quarters. Even though the U.S. exports less than ~5%
of its thermal coal production, export dynamics play a critical
role in price formation for many basins and account for an
increasingly higher share of shipments for many companies.
A significant amount of new ILB production is slated for export,
and more producers in CAPP are targeting exports to offset
structural decline in the domestic market. Despite strong demand
trends over the past year, prices have continued to trend down
owing to persistent oversupply. The Japanese fiscal benchmark was
recently set at $81.80/tonne, which is down 12% from last year.
However, spot prices have continued to move lower following
weakness in 2013, with Newcastle prices now down 23% YTD and API2
prices down 8% year to date. The forward curve for 2015 Newcastle
is currently only $70/tonne. Note that the 2015 curve was at
$78/tonne when the April 1 benchmark was settled this year. Nomura
forecasts $73/tonne benchmark for the next settlement. Fig. 35:
CAPP and Seaborne Prices Effectively Linked Seaborne prices
indexed
Source: Bloomberg, Nomura research
Fig. 36: API 2 / Newcastle Prices at or near Four-Year Lows
$/tonne
Source: Bloomberg, Nomura research
Seaborne Thermal Dynamics Mimic Coking Markets Similar to the
coking coal market, many producers in the thermal market are
unwilling to close unprofitable operations owing to off-take
agreements with rail and port infrastructure investments as well as
longer-term volume commitments. Some seaborne players have been
increasing production volumes to improve unit costs on better fixed
cost absorption while FX gains have benefited Australian producers.
Similar to the seaborne met curve, the seaborne thermal cost curve
has shifted lower as producers seek to cut costs and maximize
volume leverage in order to continue to limit cash burn.
Wood Mackenzie estimates that ~10% of coal export capacity today
is over the demand base, equating to oversupply of a staggering 96
million tonnes, which helps to explain the limited impact from the
~two-month Drummond strike. Wood Mackenzie also estimates that
global thermal export utilization rates are still running at a
healthy 91%, despite the severe price weakness seen in the market.
The secular growth story in seaborne thermal coal is also fading as
slower economic growth in China coupled with stricter pollution
control policies and cheap domestic supplies are limiting export
growth. Wood Mackenzie is forecasting Chinese thermal coal imports
to rise only 1.7% in 2014 (to 230mt), while Indian exports have
been weak out the gate, down 11% in 1Q. From a U.S. perspective,
thermal exports to Europe have declined by 37% in 1Q, and we expect
that weakness is likely to continue unless the API 2 moves back to
$8690/tonne.
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API 2 Index CAPP IndexNewcastle Index PRB Index
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Nomura | U.S. Thermal Coal Outlook 16 September 2014
22
Fig. 37: World Thermal Coal Supply Curve 96mt of Surplus
Production $/tonne, not energy adjusted
Source: Wood Mackenzie, Nomura research
Fig. 38: Colombia Indonesia Australia Thermal coal export
curves, $/tonne
Source: Wood Mackenzie, Nomura research
U.S. Thermal Exports to Decline 1015mt in 2014 We believe the
U.S. thermal coal trade balance will likely be reduced by 1015mt in
2014 owing to a combination of weaker thermal coal exports and
increasing imports from Colombia. Traders we have spoken with
recently have noted significant import buys from utilities in the
southern U.S. from Colombia that has helped to buffer weakness in
the API 2 market. Also the overall ITC data set through March, show
aggregate U.S. thermal exports down 19% with exports to Europe down
38%.
Note that the McCloskey Coal group recently estimated that the
mild winter in Europe negatively impacted coal demand by 15mt. ARA
stocks have remained above 6mt as a result also partly owing to
extra coal bought as a hedge from the Drummond outage. Thermal coal
exports are running down 7% YTD through the East Coast ports that
equates to a reduction in thermal exports of only 2mt; however, we
expect to see more material declines in 2H-2014 as thermal export
contracts roll off and lagged contracts start to feel the pressure
from the recent declines in the spot market.
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Nomura | U.S. Thermal Coal Outlook 16 September 2014
23
This indicates that U.S. thermal exports are on pace to decline
10mt in 2014, which when coupled with increased thermal imports
from Colombia as well as met coal exports flowing back into the
U.S. thermal markets, suggest the potential for 15mt of incremental
thermal coal supply primarily feeding into the Eastern U.S. market.
This is a substantial amount of surplus coal that will need to be
absorbed into the market, and given aggressive expansions from low
cost ILB and NAPP producers coupled with excess stock levels in
aggregate in the East, highlights the potential for further
capacity reduction in CAPP. Fig. 39: U.S. Thermal Exports by Port
Region Mt
Source: ITC, Nomura research
Fig. 40: U.S. Thermal Exports by Destination Mt
Source: ITC, Nomura research
Fig. 41: U.S. Thermal Exports to Europe Down 38% YTD
Source: ITC, Nomura research
Fig. 42: U.S. Thermal Exports to Asia Up 6% YTD
Source: ITC, Nomura research
CAPP Coal Economic Near $8590/tonne API 2 Not only do the
reduced thermal exports create oversupply issues in the East, but
they greatly influence the value perception of Eastern coals among
U.S. utilities. The large and liquid market for U.S. thermal
products into Europe creates a viable export market when the
arbitrage is favorable, especially considering many coal producers
can avoid costly washing / prep plant fees given API 2 specs. In
our view, the consistent decline in prices for API 2 over the past
four years has significantly limited the ability for NAPP and CAPP
producers to get fair value in the U.S. market, while the ILB has
made strong inroads both domestically and in the export
markets.
We believe that API 2 prices are likely going to be range bound
in the medium term given excess supply concerns in the market. We
believe that U.S. producers are unable to export profitably into
Europe unless the API 2 price is closer to $8590/tonne, even for
unwashed product which saves coal producers ~$10/ton on processing
costs. Note that the forward curve for API 2 is below $90/tonne
until the first quarter of 2017.
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Nomura | U.S. Thermal Coal Outlook 16 September 2014
24
Fig. 43: CAPP Requires $8590/tonne API 2 to Export $/tonne
unless stated
Source: SNL, Bloomberg, Nomura estimates.
Low Margins Even for ILB and PRB Exports The U.S. has very
strong cost positions in the ILB and PRB and the below margin
comparison charts from Wood Mackenzie show that it is not just
Eastern producers in Appalachia that are struggling to export. The
ILB has the potential to still compete into Europe versus Colombia
however the margins are relatively low today. At the current spot
price for API 2 of $75/tonne, ILB producers stand to generate
positive margin near $5/tonne. Colombian producers on the other
hand generate margins near $11/ton at current API 2 prices. The
inability for U.S. producers to export at positive netbacks is a
key issue, in our view. We believe that as legacy thermal export
contracts roll off producers will seek to divert those tons back
into an oversupplied U.S. thermal market. Fig. 44: Margin
comparison between U.S. Illinois coal basin and Colombia Bituminous
$/tonne
Source: Wood Mackenzie, Nomura research
Cost Calculations Profitability at Destination PortSelect Coal
Eastern Rail Big Sandy Destination Coal API2 CIF AHeat Value
(Btu/Kcal) 12500 FOB Price at Destination ($/Mt) 76.25Destination
Rotterdam Contract Heat Value (Kcal/kg) 6,000
FOB Price at Destination ($/Mln Kcal) 12.71Price Method FOB Big
Sandy FOB price Adjusted by Heat ($/Mt) 88.31
$/Short Ton, BtuPrice (Manual) 60.35 Total Profit per Mt ($/Mt)
-18.82Price ($/Short Ton) 60.35 Total Profit per Short Ton ($/Ton)
-17.07
Price ($/MMBtu) 2.41Price ($/Mt) 66.52 Net Back to Mine
Price ($/Kcal) 9.57 Total Freight Cost to Mine ($/Mt) 40.60
Shipping Port Hampton Roads Netback Value at Mine ($/Mt)
47.71Freight to Port ($/Mt) 20.00 Price at Mine ($/Short Ton)
43.28Rail Adjustment 2.00Port Loading/Unloading 2.00 Profit at Mine
($/Mt) -18.82
Profit at Mine ($/Short Ton) -17.07Ocean Route HR to Rott
PanamaxOcean Freight ($/Mt) 11.60 Delivered Cost Unloading Cost
3.00 VAT (17% of FOB Price) 12.96Insurance 2.00 Unloading ($/Mt)
2.60
Delivery to User 11.00Cost at Destination ($/Mt) 107.12 Other
CostsCost at Destination ($/Mln Kcal) 16.99
Total Cost from FOB Port ($/Mt) 89.85Total Cost from FOB Port
(Heat Adj) 101.91Total Cost from Mine ($/Mt) 133.69
$-
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Nomura | U.S. Thermal Coal Outlook 16 September 2014
25
In addition to the negative impact from lost sales volume, we
also see the potential for significant take-or-pay penalties. We
note that Arch is likely to see penalties this year near $30mm for
take-or-pay underperformance, certainly not a trivial amount. Given
ACI earns $2.20/ton of margin in the PRB, volumes would need to
increase by more than ~10mt to offset that loss (incremental
margins are higher than overall).
We believe that PRB exports would be viable longer term as our
conversations with global traders have noted increasing
dissatisfaction with Indonesian sub-bituminous coals owing to
inconsistent qualities. PRB coals have made inroads into the South
Korean market over the past few years owing to this dynamic. We
believe the key to the long-term bullish thesis in the PRB rests
with the ability to export via new export terminals, which remain a
work in progress. We note that development of the terminals started
back in 2010 when PRB consumption was ~60mt higher than its stands
today, which suggests no shortage of capacity in the PRB, in our
view.
PRB Exports Not Viable at Current Price Levels With coal prices
for sub-bituminous delivered into South China at ~$65/ton (5000
Kcal basis), there are few opportunities for PRB basin coal to sell
into that market. Current prices are closer to breakeven, leaving
Indonesia as the key supplier. We also question the size of the
potential market for PRB in Asia owing to less favorable economics
versus Indonesia and the potential for reduced seaborne trade from
China over time. Note that the analysis below assumes shipments via
the Westshore terminal in Canada.
Currently, the supply-demand dynamics in the Pacific Basin are
not strong enough to make PRB exports economic; however, the
arbitrage level isnt too far away even at current depressed price
levels. A longer-term concern is that China will become over time
more self sufficient in its coal needs and excess material from
Indonesia would result in a surplus condition for some time. It
should be noted that PRB has logistical challenges as well given
its high volatile content that creates combustion risk.
Furthermore, the I-5 rail corridor in the northwest U.S. has
limited spare capacity and would require substantial development to
accommodate more material export volumes out of the PRB. Fig. 45:
Margin comparison between Indonesia Sub-Bit and U.S. PRB
Sub-Bituminous $/tonne
Source: Wood Mackenzie, Nomura research
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Nomura | U.S. Thermal Coal Outlook 16 September 2014
26
Coal Retirement Clear and Present Danger We see coal market
share steadily eroding over the next several years as ~58GW of coal
fired plants are retired, new capacity is constructed using
non-coal sources and old plants are retrofitted. We estimate that
at least 80mt of demand is likely to be lost over the next five
years with PRB accounting for almost 40% of the total exposure.
Arch alone has 10mt of exposure and has noted that 9% of PRB supply
is today exposed to at-risk plants or roughly 40mt. We estimate
that 16% of Western Bit supply is at risk compared to only 7% for
the Illinois Basin. We estimate the net impact near 60mt as the
majority of efficient coal plants operating today are running at
very high capacity factors and the majority of new capacity is
efficient combined cycle gas.
When combined with potential coal-to-gas switching in 2015
depending on actual gas prices, we could see U.S. thermal coal
demand decline by ~30mt in 2015, which would pressure prices
significantly and set the stage for weak realized ASPs through 2016
given the two-to-three-year contract duration for most term
deals.
There exists significant uncertainty with regards to the net
impact of coal plant retirements forecast to start in 2015 and
accelerate into 2016. Industry experts point to these plants
running near 4050% capacity factors during 2013 and higher levels
during the recent winter. AEP commented that all of its coal plants
slated for retirement operated above 90% capacity factors during
peak demand this winter. We estimate that ~40mt of net coal demand
will be impacted over the next several years.
Longer term, depending on the outcome of carbon and regional
haze legislation in the U.S., we see the potential for additional
meaningful amounts of coal plants to be retired. The EPA carbon
policy is the most critical to the future of coal in the U.S., in
our view, and the current proposal would effectively mandate
greater retirements to meet new standards and encourage more
combined cycle and renewable development. The EIA long-term
capacity forecast already shows significant expansion planned in
the gas market. Consultancy HIS projects that U.S. thermal coal
demand will steadily decline to near 600mt by 2035, and thus export
growth becomes a key factor going forward. Fig. 46: IHS Long-Term
U.S. Steam Coal Forecast Mt
Source: IHS, Nomura research
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Nomura | U.S. Thermal Coal Outlook 16 September 2014
27
Consultants Estimates Range from 4080mt of Net Impact Wood
Mackenzie estimates that coal fired units slated to retire between
now and 2016 consumed 86mt of coal in 2012 which is above the
Energy Ventures Analysis figure of 67mt but below other consultant
numbers (we have seen as high as 105mt). Regardless, there is a
significant amount of coal generation that will be affected by MATS
implementation as well as gas price movements. Wood Mackenzie
estimates that 55mt of coal is exposed to plants slated for
complete retirement while the remaining 31mt of exposure is tied to
operations that will have surviving coal plants. Fig. 47: Coal
Usage at Retiring Plants Million tons
Source: EVA, Nomura research
Fig. 48: Coal Plant Retirement Exposure by Basin Basin risk
analysis
Source: Wood Mackenzie, Nomura research
0
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mt at risk% of basinConsumption at retiring units
% of basin at risk
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Nomura | U.S. Thermal Coal Outlook 16 September 2014
28
The figure below from Wood Mackenzie highlights the regional
exposures from coal plant retirements while the figure above shows
a timeline of projected demand loss by basin from Energy Ventures
Analysis. What is interesting is that EVA and Wood Mackenzie show
significant variances with respect to the amount of PRB at risk.
Surprisingly, there is a significant amount of PRB production at
risk despite its strong relative position in the dispatch curve as
many of these plants were built smaller in scale and limit the
financial benefit from undergoing expensive environmental
retrofits.
Wood Mackenzie shows roughly 40mt at risk over the forecast
period while the EVA analysis shows roughly 70mt at risk and nearly
90mt over a longer retirement period. Other consultant reports we
have read from Hanou Energy forecast 88mt of total demand loss. We
believe the ultimate level of impacted volumes will be based on the
ability for the remaining and more efficient plants to increase
capacity factors assuming higher gas prices enable coal to dispatch
first in the merit order. Overall we see little offsetting help
from overall load growth in U.S. electricity consumption which has
been weak the past several years. Offsetting the impact from the
retirements will be the ability for other plants to increase
capacity factors as well as some potential for a greater amount of
must run plants in the East designated for grid reliability.
Location, Location, Location SNL data shows that that RFC and
SERC account for roughly 45GW of the total ~60GW forecasts to
retire, suggesting PRB will clearly be affected to some degree.
While we dont forecast the net impact to be above 20mt of exposure
as more efficient PRB plants will likely cycle up capacity factors,
we do believe the risk is greater than the market realizes,
especially from a contract bidding perspective. We believe that the
combination of few coal plants and significantly more competition
from both NAPP and ILB will create highly competitive bid dynamics
for PRB. Furthermore, we believe the railroads are unlikely to
offer reduced rates to enable more PRB to dispatch for fear of
cannibalizing their entire revenue stream. Given most PRB producers
have stretched balance sheets in addition to large latent capacity,
we would expect PRB producers to be very aggressive in bidding
levels for 20152016 deals.
Fig. 49: Coal Fired Capacity Retirements by Census Region
Source: Wood Mac