Nomura - U.S. Thermal Coal Outlook Sept2014

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

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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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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.


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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,


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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).


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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


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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


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Fig. 3: EV/EBITDA, 2015E

Source: FactSet, Nomura estimates

Fig. 4: FCF Yield, 2015E


Fig. 5: Debt to EBITDA, 2015E


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


Fig. 8: FCF Yield at Current Spot Prices, 2015E


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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


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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


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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%

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S. Atlantic 79.3 65.7 21%

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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.

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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


Fig. 18: U.S. Sub-bituminous Demand Growth Y/Y EIA data set very weak April and May


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.

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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


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

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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

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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


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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


Fig. 26: Bituminous Coal Days of Burn by Region EIA days of burn through June


Fig. 27: Detailed EIA Inventory Breakdown for June 2014 Mt


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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%

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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%


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


Fig. 30: EIA Sub-bituminous Inventory Dynamics Summer Draw Avg is 14mt Mt


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

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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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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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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


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)


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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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


Fig. 36: API 2 / Newcastle Prices at or near Four-Year Lows $/tonne


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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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


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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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


Fig. 41: U.S. Thermal Exports to Europe Down 38% YTD


Fig. 42: U.S. Thermal Exports to Asia Up 6% YTD


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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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


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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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


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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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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


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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

Nomura - U.S. Thermal Coal Outlook Sept2014

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