Executive Summary •
Is coal a sinking ship?: Over the last three years the Bloomberg Global Coal Index of 32 major publicly-‐listed coal companies has lost half of its value while broad market indices are up over 30 percent. For pure-‐play coal producers key indicators have all been trending in the same direction – downward; coal prices are down, margins are down, returns on investments are down, and share prices are down. •
•
Thermal coal demand in structural decline: We focus on thermal coal that is used chiefly for power generation and currently accounts for nearly 80% of global coal demand (on an energy-‐adjusted basis). We source detailed country-‐level projections of thermal coal demand through 2035 from the Institute for Energy Economics and Financial Analysis (IEEFA). Whereas from 2000-‐2013 global thermal coal demand grew at a compound annual growth rate (CAGR) of nearly 4%, through 2035 IEEFA projects global demand to decline at a CAGR of -‐0.1% -‐ with peak global demand coming as soon as 2016. Key drivers of this decline include changes in the structure of China's economy, increases in energy efficiency, deployment of 1,000 GW of new renewable electricity generating capacity by 2020, and stricter air pollution limits in the US and other major coal-‐consuming nations. Carbon Supply Cost Curves for thermal coal, analysis of breakeven coal prices (BECPs): Investments in thermal coal mines pose risks to both the global climate and to investor returns. We jointly analyze these risks by creating Carbon Supply Cost Curves for thermal coal production out to 2035. We source and mine-‐level data from Wood Mackenzie’s Global Economic Model database. We analyze this data to generate curves that show potential coal supply at the global and country level in terms of (1) average annual production (in million tonnes per year, or Mtpa); and (2) CTI’s estimate of cumulative lifecycle CO2 emissions (in billions of tonnes – or gigatonnes – of carbon dioxide, or GtCO2). We further calculate each mine's breakeven coal price (BECP); accounting for all potential future production, costs, and revenues, a mine's BECP is the price that delivers an asset-‐level net present value of zero (assuming a 10% real internal rate of return). Identifying key BECP levels – focus on the US, China, and seaborne export market: Combining 2014-‐2035 demand projections with Carbon Supply Cost Curves enables us to estimate the BECP of marginal thermal coal mines under (1) Carbon Supply Cost Curves – Evaluating Financial Risk to Coal Capital Expenditures Key Takeaways -‐
We forecast global thermal coal demand to peak in 2016 and then declines (2035 demand 4% < 2013 level) -‐
Risks to profitability for 3 6% of potential thermal coal production through 2035 -‐ including half of production from new mines -‐
Strong headwinds to greatly expanded US coal exports to Asia -‐
Excluding China, through 2025 we find $112 billion of mining capex associated with potential high-‐
cost production -‐
Non-‐China high-‐cost capex concentrated in US as well as export mines of A ustralia, Mozambique, Botswana, Indonesia, and South Africa -‐
Exposure to high-‐cost capex for diversified miners, major US and Chinese coal producers, and Asian industrial conglomerates -‐
Amid low returns, several large diversified miners have been selling thermal coal assets To assess risks to thermal coal production through 2035, we base our analysis on cost and supply data from Wood Mackenzie's Global Economic Model (GEM) and demand projections from the Institute for Energy Economics and Financial Analysis (IEEFA). Our work is intended to help investors scrutinize company investments in thermal coal. Analysts CTI: ETA: James L
eaton Mark Fulton •
Reid Capalino IEEFA Luke Sussams Andrew Grant Energy Economics IEEFA 10 Oct 2014 Clyde H enderson T1im Buckley rd
October 10 2014 IEEFA's "low-‐demand" scenario; and (2) the International Energy Agency's "450 scenario", which is consistent with at least a 50% chance of limiting future climate change to less than 2°C. Mines with production costs above our threshold BECP levels face the prospect of low financial returns. We focus our supply-‐demand analysis chiefly on three key thermal coal markets: China’s domestic market (50% of 2013 global demand), the US domestic market (13% of 2013 global demand), and the seaborne thermal export market (18% of 2013 global demand).1 • Seaborne export market – 62% of potential production above key BECP of $75/tonne: Demand for thermal coal imports has spurred investment in developing or expanding thermal coal export mines from the Indonesian archipelago to the hinterland of Australia to the plains of Mozambique. The IEEFA "low-‐demand" scenario, however, projects global demand for thermal coal imports to peak within this decade. We account for differences in the energy content and transport costs of thermal coal exports from different mines by standardizing BECPs in terms of a “Newcastle-‐equivalent” price, (for details, see our methodology section). After making these adjustments, through marginal suppliers to the seaborne export market have a "Newcastle-‐equivalent" BECP of $75/tonne (and a “cash cost” of production close to $70/tonne). 62% of potential export production has a BECP above this level -‐ including 93% of potential production from "greenfield" (i.e. new) mines. China and Indonesia account for over half of total potential export production above $75/tonne. In the case of China, currently the world’s largest importer of thermal coal, IEEFA projects that in 2016 China’s thermal coal consumption will peak, demand for imports will drop, and by the end of the decade the country will potentially return to being an opportunistic next exporter of thermal coal. This may seem surprising, but note that China only became a net coal importer in 2009; by comparison, as of 2005 China was exporting nearly 70 million tonnes of thermal coal (33 million tonnes of net exports), or roughly the same amount as South Africa has exported for much of the past decade. Elsewhere, in every exporting country except for Colombia, South Africa, and Vietnam, however, a majority of potential export production through 2035 is above the IEEFA $75/tonne BECP threshold. In a 450 scenario the "Newcastle-‐equivalent" BECP of marginal suppliers falls to $72/tonne, with 71% of potential export production having costs above this level. Though a Newcastle price of $72-‐75/tonne is actually slightly higher than the current spot price of $68/tonne, it remains well below the average 2008-‐2012 price of $100+/tonne -‐ suggesting that high-‐cost export producers are in for a bleak future. • Well-‐supplied seaborne market challenges growth ambitions for US exports: A Newcastle price of $75/tonne will challenge the ambitions of miners throughout the world to increase thermal coal exports. In the United States, for example, we find 31.4 Mtpa of potential export capacity to have a Newcastle-‐equivalent BECP below $75/tonne; this equates to only 20% of potential export capacity through 2035, and (even after adjusting for differences in energy content) is below the 47.1 Mt of thermal coal that the US exported in 2013. Our analysis underscores the risks involved in spending billions of dollars on port and rail infrastructure to increase exports of US thermal coal to the Pacific. Combined with recent short-‐term trends – revenues from US thermal coal exports declining 15% from 2012-‐2013, cancellation of five proposed export terminals in the Pacific Northwest and Gulf Coast – our 1
When analyzing the export market, we adjust for differences in energy content and transport costs by standardizing BECP values in terms of a "Newcastle-‐equivalent" BECP (the "Newcastle free-‐on-‐board" price being a key pricing benchmark for thermal coal exports in the Pacific market). Our analysis of domestic markets adjusts for differences in energy-‐content but does not adjust for transport costs. 10 Oct 2014 2 findings suggest a need for industry to ratchet down its expectations for growth in US thermal coal exports from the Powder River Basin to Asian markets. •
•
China's domestic market – 28% of potential production above key price level of $60/tonne: China is the behemoth of thermal coal. In 2013, the country both produced and consumed nearly half of the world's thermal coal. IEEFA, however, projects that Chinese demand for thermal coal will peak in 2016 and decline modestly thereafter through 2035. Our analysis of the economics of Chinese coal production acknowledges how extensive state ownership may enable mines to operate for extended periods at prices below their BECP levels; as a result, we focus on "cash costs" of production. Under the IEEA low-‐demand scenario marginal suppliers to China’s domestic coal market have cash costs of $60/tonne (and, as it happens, BECPs very close to this level); 28% of potential production has costs above this level. This suggests that a low-‐demand scenario will hasten the exit of high-‐cost mines that is already underway in China. In a 450 scenario the cash costs of marginal suppliers to China's domestic market fall to $48/tonne, which is below the cost of 46% of potential production (underscoring the transformation of Chinese energy production that is needed on a 2°C climate pathway). US domestic market – 14% of potential production above key BECP level of $53/tonne: IEEFA projects the recent decline in US domestic thermal coal demand to continue through 2035 (with annual demand declining 16% by 2020 and 34% by 2035). In this scenario marginal suppliers to the US domestic market have a BECP of $53/tonne. 14% of potential production has costs above $53/tonne. Given significant regional variation in coal costs and prices throughout the US, we then converted this $53/tonne price into regional prices (which ranged from $17/tonne for the Powder River Basin to $74/tonne for Central Appalachia) to indicate region-‐specific exposure. This analysis identified risks chiefly to potential high-‐cost production from older mines in Central and Northern Appalachia, along with some higher-‐cost Powder River Basin and Western Bituminous coal. We note that many Appalachian producers are already experiencing financial difficulties, with two of the region's major producers (James River Coal and Patriot Coal) each filing for bankruptcy over the last few years. In a 450 scenario the BECP of marginal suppliers to the US domestic market falls to $37/tonne, which is below the cost of 34% of potential production. •
•
Take-‐or-‐pay contracts, government subsidies slow exit of high-‐cost mines: Economic theory predicts that, in the short term, miners on the wrong end of the supply curve will continue to produce as long as prices remain above their cash costs of production. This dynamic can slow the exit of high-‐cost capacity, and is compounded by the prevalence of "take-‐or-‐pay" contracts (e.g. for rail capacity) that – by increasing the share of fixed as opposed to variable costs – lower miners' cash costs of production. Another significant barrier to exit of high-‐cost capacity is government support to financially troubled coal producers, whether in the form of reduced rail tariffs in Russia or low-‐cost loans in China. Particularly outside the OECD, such policies may serve to sustain production from high-‐cost mines – thereby sustaining oversupply and exerting continued pressure on prices. In a scenario of structurally declining demand, such policies exacerbate risks for higher-‐cost mines that do not enjoy extensive government support. For private sector, $112 bn of risky potential capex – chiefly related to new mines: Having estimated potential thermal coal production through 2035 above key cost thresholds, we then examine the capital expenditures (capex) through 2025 associated with 10 Oct 2014 3 •
•
this production. Excluding China (where a significant portion of capex is financed via state-‐
owned banks or other public-‐sector monies),2 we find $112 billion of potential capex on high-‐cost projects.3 Roughly three-‐quarters of this total ($92 billion) relates to so-‐called "greenfield" (i.e. new) mines, as opposed to so-‐called "brownfield" (i.e. existing) mines. Non-‐China countries with significant high-‐cost potential capex include Australia ($35 billion), the US ($17 billion), Mozambique ($15 billion), Botswana ($11 billion), Indonesia ($11 billion), and South Africa ($6 billion). With the exception of the US (where only $3 billion of its $17 billion high-‐cost capex total relates to exports), in each of these other countries potential high-‐cost capex is intended to stimulate export production. Investors can use this capex analysis to engage with companies on reducing exposure to financially risky projects. Through 2035, $112 billion in non-‐China potential high-‐cost capex is associated with cumulative emissions of 42 GtCO2. Including port/rail infrastructure costs could double overall capex for greenfield projects: Our capex estimates do not include the cost of building new infrastructure such as rail lines or port export terminals. For 2000-‐2013, however, the IEA calculates such transport-‐
related costs to be 49% of average annual upstream coal supply investment (i.e. $30 billion, versus $31 billion for investment in coal mines). This suggests that including such transport-‐related costs could double our 2014-‐2015 ex-‐China estimate of overall financially risky greenfield capex to over $200 billion. Global supply/demand outlook casts doubt on need for new high-‐cost mines: We decompose potential thermal coal production through 2035 depending on whether it (1) comes from existing mines (5,689 Mtpa, or 71% of total) or new mines (2,313 Mtpa, or 29% of total); and (2) is from a mine with a BECP below (5,147 Mtpa, or 64% of total) or above (2,855 Mtpa, or 34% of total) the relevant BECP threshold for that market. Comparing these estimates with IEEFA's projected average thermal and lignite combined global demand through 2035 (6,745 Mtpa), we find production from just existing mines to satisfy 85% of projected global thermal coal demand; adding production from low-‐cost new mines satisfies over 100% of projected demand. Moreover, including potential production from countries outside the Wood Mackenzie database – which we approximate as equal to nearly one-‐quarter of 2014-‐2025 global demand – provides an additional buffer between potential supply and projected demand. We also only analyzed future production from potential capex spent up to 2025 – including additional expenditures post-‐2025 (i.e. related to expanding existing mines) could further close the gap between projected demand and production from existing mines. In practice, geographic separation between existing mines and sources of growing demand provide an added impetus for development of new mine; and individual producers, who often specialize in a particular region or resource type, may continue to pursue greenfield opportunities even if existing global supply is adequate to 2
Note that this is also the case in certain other developing countries, such as India and Vietnam (with only the latter included in our supply data). Comparing ownership structures for hard coal production capacity inside and outside the Organization for Economic Cooperation and Development (OECD), private (listed and unlisted) companies own 92% of production capacity inside OECD countries versus only 34% outside the OECD. That said, in non-‐OECD countries, state ownership of coal production capacity is relatively low in export-‐focused producers such as Indonesia, Colombia, and South Africa. 3
Including China, the total increases from $112 billion to $230 billion. Note, however, that all capex totals discussed in this paper relate to projects that companies have the potential to develop, rather than to projects that they necessarily intend to develop. Therefore, in practice, actual capex committed to projects above a given price level may be considerably lower than the potential total. 10 Oct 2014 4 meet global demand. That said, at a high level the above comparison indicates a weak macro-‐level justification for investment in new high-‐cost mines. •
Wide range of companies exposed to high-‐cost thermal coal capex: The companies exposed to the highest absolute levels of high-‐cost capex include diversified miners (e.g. Rio Tinto and BHP Billiton), China's largest coal producers (e.g. Shenhua Energy)4, pure-‐play coal miners in the US (e.g. CONSOL Energy, Alpha Natural Resources, Peabody Energy) and Australia (e.g. Bandanna Energy), Asian industrial conglomerates (GVK, Adani, Mitsubishi), as well companies developing prospective mines in aspiring export countries (e.g. Botswana's Asenjo Energy). •
•
•
Can thermal coal producers go from pause to rewind on capex?: Surveying 60 publicly-‐
listed thermal coal producers, we find the rate of growth in annual capex to have been slowing since 2011 in response to diminishing returns and weak credit ratings. From 2012-‐
2013, combined annual capex of these companies actually declined slightly (from $27 billion to $25 billion), the first such decline since at least 2000. As described above, however, most companies retain a backlog of projects ready to be ramped up given an upswing in coal prices. Moreover, 2013 capital expenditures of $25 billion remained more than 3X the cash that these firms returned to shareholders via buybacks and dividends. The challenging outlook for thermal coal mines suggests that investors can bolster future returns by advocating that companies not just pause but begin to reduce annual thermal coal capex. Several diversified miners disposing of thermal coal assets: Among the world's largest thermal coal producers are diversified miners that also produce iron ore, copper, uranium, zinc, and precious metals. Through 2025, we estimate the four largest diversified coal producers (Anglo American, BHP Billiton, Rio Tinto, and Glencore Xstrata) to have been $2-‐5 billion of potential capex exposure to high-‐cost thermal coal export mines. It is worth noting that two of these companies (Rio Tinto and BHP Billiton) have recently sold or are in the process of spinning-‐off major thermal coal mines in the US, South Africa, and Australia (in addition to curtailing all new capex related to thermal coal). Vale, another large diversified miner, recently exited thermal coal production by selling assets in Colombia and reducing its Australian exposure. With positive coal-‐related cash flows harder to find and regulatory risk profiles increasing, other products simply offer better prospects. Investors in such companies ought to prioritize engaging with management to understand company plans regarding capex and M&A related to thermal coal. Reference 2°C carbon budget of 189 GtCO2 exhausted entirely from lower-‐cost mines: As Carbon Tracker has pointed out in its previous research, staying within a 2°C global "carbon budget" will require a significant reduction in future c o a l demand.5 Measures necessary to achieve this reduction include stronger climate policies, heightened energy efficiency, and broader deployment of renewable energy sources. As a reference point, 4
Data limitations prevent us from accurately measuring company-‐level exposure to potential capex within China's domestic market, and so we show such data at the provincial level. That said, for several of China’s largest producers, we still identify exposure to potential high-‐cost capex via ownership of export mines in Australia and other countries. 5
The target to limit global warming to 2°C was formalized in the UNFCCC Cancun Accord. Organizations including NASA, the IEA and the World Bank have warned of catastrophic impacts that will result from warmer temperatures. 10 Oct 2014 5 we estimate a 2035 global carbon budget for thermal coal by drawing on projected carbon-‐
dioxide (CO2) emissions in the most recent 450 Scenario from the International Energy Agency (IEA)6; our estimate for this budget is 189 GtCO2. We find that this budget can be entirely exhausted through potential production below threshold BECP levels in export or relevant domestic markets. This highlights curtailing development of high-‐cost coal mines to be not just a prudent move for investors but also necessary for a pathway to a stable climate. Key details on high-‐cost projects The table below surveys potential production, carbon emissions, and capex associated with mines that have a BECP above key threshold levels the seaborne export market as well as the domestic markets of China, the US, and other countries. Note that (1) we examine potential production and carbon emissions only through 2035 due to data limitations; and (2) we focus on capex over the period of 2014-‐2025 in order to emphasize a timescale that is relevant for investors. Table 1: Potential production, carbon, and capex above threshold cost levels in key markets Threshold BECP
($/tonne)
Seaborne export market
% of category total (all BECP levels) US domestic
% of category total (all BECP levels) China domestic
% of category total (all BECP levels)* ROW domestic**
% of category total (all BECP levels) 75
53
60
65
2014-‐2035 Avg. Annual Potential Production
(Mtpa)
2014-‐2025 Capex
(2014 $bn)
Brownfield Greenfield
31.7
107.1
49%
95%
5.2
8.8
23%
35%
28.3
45.6
25%
39%
1.0
2.4
6%
16%
Total
138.8
78%
13.9
29%
73.9
32%
3.4
11%
2014-‐2035 Cumulative Emissions
(GtCO 2 )
Brownfield Greenfield Total Brownfield Greenfield
676.0
757.4
1,433.4
26.8
30.0
46%
93%
62%
46%
93%
67.2
39.4
106.5
2.7
1.6
12%
18%
14%
12%
18%
922.2
311.8
1,234.0
36.5
12.3
29%
28%
28%
29%
28%
39.9
41.6
81.5
1.6
1.6
9%
26%
14%
9%
26%
Total
56.8
62%
4.2
14%
48.9
28%
3.2
14%
Total
% of global total (all BECP levels)
66.2
30%
163.9
61%
230.1
47%
1,705.3
60%
1,150.2
40%
2,855.4
36%
67.5
60%
45.5
40%
113.1
36%
Total ex-‐China
% of ex-‐China total (all BECP levels)
19.7
25%
91.9
73%
111.6
55%
403.1
23%
652.8
65%
1056.0
38%
16.0
23%
25.9
65%
41.8
38%
Note: Key BECP thresholds determined using IEEFA’s low-‐demand scenario. Values shown reflect potential capex/production/emissions totals above the key BECP threshold in that particular market (e.g. in the seaborne export market, there is potential brownfield production of 676 Mtpa with a BECP above $75/tonne). Values in “% of category total (all BECP levels)” rows show the number in the above row as a percentage of the overall total (at all BECP levels) for that particular category (e.g. in the seaborne export market, 46% of potential brownfield production is above $75/tonne). Column totals will not sum to 100%. Values in “% of global total (all BECP levels)” row show the number in the above row as a percentage of the overall global total (at all BECP levels) within that particular category (e.g. in the seaborne export market, 60% of global potential brownfield production is above $75/tonne). *China $60/tonne level determined via focus on “cash cost” rather than BECP (though, for the threshold level we identify, the two are very close). **ROW domestic category includes 13 countries in the Global Economic Model other than the US and China.7 Source: Energy Economics using Wood Mackenzie Global Economic Model, CTI-‐ETA analysis 2014 6
This scenario shows a global energy sector on a trajectory with a “near 50% chance of limiting the long-‐term increase in the average global temperature to two degrees Celsius (2°C).” International Energy Agency (IEA), World Energy Outlook 2013 (WEO 2013), 2013, 645 http://www.worldenergyoutlook.org/publications/weo-‐
2013/IEA. 7
These are Australia, Botswana, Canada, Chile, Colombia, Indonesia, Mongolia, Mozambique, New Zealand, Russia, South Africa, Venezuela, and Vietnam. 10 Oct 2014 6 •
•
•
•
•
•
In total across both export and domestic markets, through 2035 there is 2855.4 Mtpa or 113.1 GtCO2 of high-‐cost potential thermal coal production (equivalent to 36% of total potential production over this period from mines at all cost levels) From 2014-‐2025, there is $230 billion of capex associated with this high-‐cost potential thermal coal production (47% of total capex over this period from mines at all cost levels) o Excluding China, from 2014-‐2025 there is $112 billion of capex associated with high-‐
cost potential production (55% of total capex over this period from mines outside of China at all cost levels) ! A strong majority of this capex relates to firms in the private sector. o This $112 billion of capex breaks down into $77 billion from “brownfield” projects (i.e. sustaining and expanding existing mines) and $92 billion from “greenfield” projects (i.e. sustaining and expanding new mines) o For 2014-‐2025 greenfield capex outside of China, 73% is above key BECP thresholds of the export or relevant domestic market Through 2035, potential production in the Wood Mackenzie GEM database from (1) existing mines; and (2) new mines below our BECP thresholds is sufficient to meet over 100% of projected thermal coal demand in the IEEFA “low-‐coal demand” scenario o Including potential production from mines which are not included in the GEM database (e.g. those in India) – which IEEFA estimates will equal 24% of global thermal coal demand through 2035 (i.e. 1,552 Mtpa) – would reduce the required contribution from high-‐cost existing mines or low-‐cost new mines within the GEM database In the seaborne export market, through 2035 there is 1433 Mtpa or 56.8 GtCO2 of high-‐cost potential thermal coal production (equivalent to 62% of potential export production over this period) 2014-‐2025 capex associated with this high-‐cost seaborne export production is $139 billion (equivalent to 78% of total export capex over this period) o This breaks down into $31.7 billion of high-‐cost export capex from brownfield projects (49% of total brownfield export capex) and $107 billion of high-‐cost export capex from greenfield projects (95% of total greenfield export capex) In the US domestic market, through 2035 there is 106.5 Mtpa or 4.2 GtCO2 of high-‐cost potential thermal coal production (equivalent to 14% of potential US domestic production over this period) o The relatively low total for high-‐cost production in the US market under the IEEFA scenario reflects, in part, the size of total potential US thermal coal production over this period (at all cost levels) in the data we use. For example, 2014-‐2035 US potential average annual thermal coal production of 706.5 Mtpa (at all cost levels) is 9% lower than 2013 US thermal coal demand of 778 million tonnes.8 8
US Energy Information Administration (EIA), "US Coal Consumption by End-‐Use Sector, 2008-‐2014," http://www.eia.gov/coal/production/quarterly/pdf/t32p01p1.pdf 10 Oct 2014 7 •
•
•
2014-‐2025 capex associated with this high-‐cost US domestic production is $13.9 billion (equivalent to 29% of US domestic capex over this period) o This breaks down into $5.2 billion of high-‐cost capex from brownfield projects (23% of total US domestic brownfield capex) and $8.8 billion of high-‐cost capex from greenfield projects (35% of total US domestic greenfield capex) In China’s domestic market, through 2035 there is 1234 Mtpa or 48.9 GtCO2 of high-‐cost potential thermal coal production (equivalent to 28% of potential domestic Chinese production over this period) 2014-‐2025 capex associated with this high-‐cost domestic Chinese production is $73.9 billion (equivalent to 32% of domestic Chinese capex over this period) o This breaks down into $28.3 billion of high-‐cost capex from brownfield projects (25% of total domestic Chinese brownfield capex) and $45.6 billion of high-‐cost capex from greenfield projects (39% of total domestic Chinese greenfield capex) Potential export production above and below $75/tonne BECP by geography In analyzing the market for thermal coal exports, we use IEEFA's projection that annual demand through 2035 will average 850 Mtpa (versus expected 2014 demand of roughly 1000 Mtpa); after adjusting for differences in transport costs and energy content, marginal supply necessary to meet this level of demand has a BECP $75/tonne. For the 10 largest countries with the largest exposure to potential capex on high-‐cost export mines through 2025, the map below compares potential capex below (purple circle) and above (green circle) this key $75/tonne threshold. Figure 1: The High-‐Carbon – Capital Expenditures Radar Map for Export Thermal Coal Key high-‐carbon (>1 GTCO2) and high-‐cost (>$75/tonne BECP) locations for potential export thermal coal capex 10 Oct 2014 8 2014-‐2025 capex associated with high-‐cost thermal coal export production is $138 billion (or $93 billion excluding China); greenfield projects dominate this total, accounting for $107 billion overall (or $81 billion excluding China). Examples of financially risky greenfield export mine projects abound, such as development of the Galilee coal basin in central Queensland, Australia, which through 2025 carries and infrastructure-‐related capex of a proposed $24 billion.9 Recommendations for Investors To promote better monitoring and avoidance of risks related to high-‐cost thermal coal capex, we propose the following recommendations for asset owners and fund managers to consider: 1. Understand the exposure of your portfolio/fund to the upper-‐end of the cost curve, both in terms of volume of embedded carbon and projected profitability of production returns (as in the future the two may become linked). Understand how company management are assessing and managing these risks and how projects are "tested" against them. 2. Identify the companies with the majority of capex earmarked for high-‐cost projects, especially high-‐cost, capital-‐intensive projects (since capital-‐intensive projects take longer to pay out and so are exposed to a longer period of risk). 3. As a starting point, focus engagement on projects requiring over $75/tonne in export markets and regional equivalents of $53/tonne in the US domestic market and $60/tonne in the Chinese domestic market. 4. Set thresholds for portfolio companies with respect to exposure to projects at the high-‐end of the cost curve. 5. Make it known to company management that you seek value over volumes, even if that means reducing the size of the company's asset base. Also, emphasize that strategies to create shareholder value must be robust even under scenarios of higher project costs and/or lower coal prices. 6. Ensure that company remuneration policies are consistent with long-‐term shareholder return objectives, rather than just rewarding reserves replacement or capital investment. 7. Require improved disclosure of the demand and price assumptions/scenarios underpinning capex strategy. 8. Support transparency of company exposure to the cost curve and impairment trigger points, for example through annual publication of sensitivity analyses/stress tests to different coal price scenarios. 9
For more on the Galilee project, see discussion of Australia in the "Examining impacts for exporters of thermal coal at a country level" section below. 10 Oct 2014 9 DISCLAIMERS " CTI is a non-‐profit company set-‐up to produce new thinking on climate risk. CTI publishes its research for the public good in the furtherance of CTIs not for profit objectives. Its research is provided free of charge and CTI does not seek any direct or indirect financial compensation for its research. The organization is funded by a range of European and American foundations. o CTI is not an investment adviser, and makes no representation regarding the advisability of investing in any particular company or investment fund or other vehicle. A decision to invest in any such investment fund or other entity should not be made in reliance on any of the statements set forth in this publication. " CTI has commissioned Energy Transition Advisors (ETA) to carry out key aspects of this research. The research is provided exclusively for CTI to serve it’s not for profit objectives. ETA is not permitted to otherwise use this research to secure any direct or indirect financial compensation. The information & analysis from ETA contained in this research report does not constitute an offer to sell securities or the solicitation of an offer to buy, or recommendation for investment in, any securities within the United States or any other jurisdiction. The information is not intended as financial advice. This research report provides general information only. The information and opinions constitute a judgment as at the date indicated and are subject to change without notice. The information may therefore not be accurate or current. The information and opinions contained in this report have been compiled or arrived at from sources believed to be reliable in good faith, but no representation or warranty, express or implied, is made by CTI or ETA as to their accuracy, completeness or correctness. Neither do CTI or ETA warrant that the information is up to date. " The underlying supply and cost analysis in this report, prepared by CTI-‐ETA, is based on data licensed from the Global Economic Model of Wood Mackenzie Limited. Wood Mackenzie is a Global leader in commercial intelligence for the energy, metals and mining industries. They provide objective analysis on assets, companies and markets, giving clients the insights they need to make better strategic decisions. The analysis presented and the opinions expressed in this report are solely those of CTI-‐ETA. www.et-‐advisors.com www.carbontracker.org @carbonbubble 10 Oct 2014 10 Contents 1. Introduction -‐ Carbon Asset Risk ................................................................................................. 12 2. Thermal coal demand -‐ nearing a global peak ........................................................................... 16 3. Recent financial trends in the global coal industry .................................................................... 24 4. Carbon Supply Cost Curves: methodology for coal markets ...................................................... 49 5. Detailed Results of Carbon Supply Cost Curves ......................................................................... 60 Case Study – The Galilee Coal Basin ........................................................................................... 83 6. Analysis of thermal coal capital expenditures -‐ $488 billion through 2025 ............................... 88 10 Oct 2014 11 1. Introduction -‐ Carbon Asset Risk In April 2013 Carbon Tracker Initiative (CTI) published Unburnable Carbon 2013: Unburnable Carbon and Stranded Assets.10 This study defined a global "carbon budget" compatible with limiting the atmospheric concentration of carbon dioxide (CO2) to 450 parts per million (ppm) and future temperature increases to 2 degrees Celsius (2°C) or up to 3°C. CTI compared its carbon budgets against the quantity of carbon attributed to fossil fuel reserves of listed companies.10 This analysis provided a snapshot in time of company exposure to existing fossil fuel reserves as well as of aggregate capital expenditures (capex) to develop new fossil fuel reserves ($674 billion in 2012 for the 200 largest listed oil, gas, and mining companies).11 CTI's 2013 study concluded that "if listed companies are allocated their proportion of the carbon budget relative to total reserves (a quarter), they are already around three times their share of the budget" to give a reasonable chance of achieving a 2°C outcome.12 The question then becomes, if society demands a 2°C pathway, and considering the many other fossil-‐based energy demand drivers, how will these reserves work out? •
Will there be stranded assets in terms of underperforming assets? In effect, will capital be wasted developing reserves in coming years before climate constraints becomes more binding and/or alternatives combined with efficiency and changes to economic growth lead to a material fall in demand? •
This leads to questions from investors as to which are the most likely assets to be at risk of becoming non-‐economic and who the winners and losers are likely to be as a result. •
In May 2014 CTI, in collaboration with Energy Transition Advisors (ETA), released Carbon Supply Curves: Evaluating Oil Capital Expenditures,13 which looked at the interaction of forecast supply out to 2050 with both reference carbon budgets and forecast demand/price scenarios. •
This thermal coal study follows a similar trajectory and structure, with some differences, most notably that thermal coal markets are more segmented and less fungible. Export markets and related countries are treated separately from the dominant Chinese domestic market and other domestic markets. The US is split out within domestic markets too. •
Indeed we have retained as much of the common structure with our previous oil report and commentary for consistency. 10
Carbon Tracker Initiative (CTI) and the Grantham Research Institute, Unburnable Carbon 2013: Wasted capital and stranded assets, 2013, http://carbontracker.live.kiln.it/Unburnable-‐Carbon-‐2-‐Web-‐Version.pdf 11
CTI and the Grantham Research Institute, Unburnable Carbon 2013, 34. 12
CTI and the Grantham Research Institute, Unburnable Carbon 2013, 22. The 2013 study also found existing reserves of listed companies to exceed their pro-‐rata share of a carbon budget for a 3°C future. 13
Carbon Tracker Initiative and Energy Transition Advisors, Carbon Supply Cost Curves: Evaluating Financial Risk to Oil Capital Expenditures, May 2014, http://www.carbontracker.org. 10 Oct 2014 12 \Markets allocate the carbon “budget” – focus on thermal coal •
Since the publication of Unburnable Carbon 2013, CTI and its research partner, Energy Transition Advisors (ETA), have moved on to analyze carbon outcomes on the basis that markets will be the determining forces in allocating any global “carbon budget." •
The demand and supply interaction of fossil fuel markets setting commodity prices will in economic terms determine the viability of fossil fuels down to the project or asset level •
In this study, within the context of total coal markets, we focus specifically on thermal coal -‐ the source of 22.5% of current total primary energy demand and roughly 35% of current global CO2 emissions.14 Future demand for thermal coal will be affected by climate-‐related policies and other environmental policies, such as those related to air and water. Note that supply constraints are also possible. Demand will also be affected by competition from alternative sources of energy – renewable energy being the most obvious. Demand will be heavily affected by efficiency measures, including improved efficiency in processes or products demanding fossil fuels, •
•
•
•
The shape of world economic growth will affect demand – with the developing and emerging world dominant at the margin. •
Demand then has to interact with the supply stack or curve; the supply curve being based on production volumes at different economic breakeven coal prices (BECP). We express our BECPs in real 2014 dollars. So if demand were to prove weaker than expected due to environmental policy or other factors, how much exposure is there to risky investments at the higher BECP end of the supply curve? •
•
•
•
Is there significant capital expenditure planned in th e rm a l c o a l that looks uneconomic without significantly higher prices? If so, is this related to the expansion of existing mines or the development of new greenfield locations? At the macro level, how will these supply curves (and associated break even prices) tie into a global carbon budget? We address these questions by completing an analysis of carbon asset development risk, based on comprehensive market-‐based demand and cost driver scenarios. Ultimately, this analysis of thermal coal projects will demonstrate how investors can incorporate scenarios other than "business as usual" into both company and project risk. It will also enable them to assess the risk in corporates investing in production with high breakeven price requirements while incurring significant capital expenditure outlays and lead to engagement around this.
14
IEA, WEO 2013, 2013, Annex A -‐ Tables for Scenario Projections, 574. 10 Oct 2014 13 Breakeven coal prices (BECPs) •
•
The starting point for any new coal project development is the Breakeven Coal Price (BECP), which can be thought of as the per-‐tonne marginal cost of developing an asset. In the project analysis model of our data provider, Wood Mackenzie, a project's BECP is the price that -‐ considering all future cash flows (i.e. costs, revenues, government take -‐ are needed to deliver an asset-‐level net present value (NPV) of zero assuming a 10% discount rate17. For further details, see our methodology section below. Bridging the carbon and economic analysis gap: carbon supply cost curves •
In our study of oil, we introduced a new concept, Carbon Supply Cost Curves. And continue with that in relation to thermal coal. Traditionally potential supply or production levels are expressed in terms of thermal coal production (normally in terms of million tonnes per annum, Mtpa) against supply cost (in the case of thermal coal mostly in terms of a cash cost rather than Breakeven Coal Price, or BECP, which we focus on). These potential production supply curves are commonly used by financial analysts and corporates. By converting potential production of thermal coal (in terms of Mtpa) into potential production of carbon (in terms of billion tons of carbon dioxide, or GtCO2) we relate the economic market to the carbon outcome. •
In order to analyze the carbon content of future production, we take as inputs Wood Mackenzie's estimates of (1) potential total production (expressed in terms of Mtpa); (2) the "cash costs” associated with this production; and (3) the breakeven coal price (BECP) associated with this production. Using these three inputs enables us to generate both global and country-‐level supply curves for potential production of thermal coal through 2035. We combine our supply curves with country-‐level estimates of thermal coal demand through 2035 under (1) a “low-‐coal demand” scenario based on analysis by the Institute for Energy Economics and Financial Analysis (IEEFA); and (2) a “450 ppm” scenario as determined by the International Energy Agency (IEA).15 Intersecting these curves implies an equilibrium quantity and price (expressed in terms of BECP) for key thermal coal markers through 2035. •
•
To determine the carbon outcome associated with a given thermal coal market, we convert potential production (in terms of Mtpa) to cumulative emissions in terms of billions of tonnes of carbon dioxide ( GtCO2). To put GtCO2 figures in context, we compare them against the 2035 global carbon budgets (for fossil fuels in general and thermal coal in particular) consistent with limiting future warming to 2°C; to allocate a share of the overall 2°C 2035 global carbon budget to thermal coal, we use the share of overall fossil fuel emissions from thermal coal under the IEA’s 450 scenario. 15
The IEA’s 450 scenario shows a global energy sector on a trajectory with a “near 50% chance of limiting the long-‐term increase in the average global temperature to two degrees Celsius (2°C).” International Energy Agency (IEA), World Energy Outlook 2013 (WEO 2013), 2013, 645 22 Sep 2014 14 •
This method of analysis allows us to determine: o
o
o
Investment risk to higher-‐cost, higher-‐carbon assets; The capital expenditure associated with the assets; and The challenge to meeting a 2°C outcome and the risk that may bring to longer-‐ term investment in fossil fuels Comprehensive models of thermal coal supply and demand •
The most comprehensive approach is a broad economic model that incorporates all global demand and supply for all energy markets and solves the outcome at a very granular project level. The leader in this kind of energy analysis at the global level is the International Energy Agency (IEA), whose annual World Energy Outlook (WEO) projects future energy trends under both business-‐as-‐usual and carbon-‐constrained scenarios. Relative to an economy-‐wide model such as that used in the IEA's WEO publications, our approach is more focused on exploring the supply curve for thermal coal in detail and comparing estimated supply costs with potential future demand conditions. It is more of a partial or "bottom-‐up" approach, but does still draw from and fit into a more comprehensive framework. Indeed, we use two scenarios from the IEA's WEO 2013 study -‐ the New Policies Scenario and the 450 Scenario21 -‐ as two overall key reference points and important sources for analysis of thermal coal-‐related supply and demand trends. Focus on upstream capital expenditure (capex) • From the perspective of carbon asset risk, the fundamental issue that investors and financial intermediaries face is the risk to future capital expenditures (capex) -‐ in other words, under what conditions will this investment be rewarded? This can be split into capex on existing mines (i.e. “brownfield” mines) and capex on new mines (i.e. “greenfield” mines). • While the economic viability of some existing thermal coal assets could be threatened by lower commodity prices, we believe that future capital expenditures is the key to mitigating carbon and that this is where the key risks for investor lie. • Starting with identifying the highest-‐cost potential production, we then drill down by location and assess how much capex is associated with bringing that production on line. Importantly, we also focus on capex that is funded by commercial banks and private capital markets (rather than via funds from state entities); for CTI, the focus has been on future capex from listed companies in the private sector, rather than on capex of fully state-‐owned companies. • To support current investor engagement activities, we explore in particular carbon asset risk implications for companies with thermal coal assets.
•
22 Sep 2014 15 16
2. Thermal coal demand -‐ nearing a global peak •
Thermal coal demand -‐ in structural decline with a global peak in 2016: Demand for thermal coal is beginning a long structural decline. From 2000-‐2013 global demand for thermal coal grew at a compound annual growth rate (CAGR) of 3.7%. We project, however, that global thermal coal demand will peak by 2016 (coincident and driven by a peak in demand from China); from 2020-‐2035, global demand will plateau and decline at a CAGR of -‐0.2%. This projection is the result of detailed country-‐level analysis from the Institute for Energy Economics and Financial Analysis (IEEFA). •
Key drivers include economic transitions, energy efficiency, renewables/gas/hydro: Drivers of the looming peak in global thermal coal demand include: (1) China's transition to a less energy-‐intensive pattern of economic growth, along with; (2) sustained increases in energy efficiency in China and other major coal-‐consuming nations (modeled off of Japan's post-‐Fukushima success in reducing electricity use per unit of real GDP by 15% over a three-‐
year period); (3) deployment of 1,000 GW of new renewable wind, solar and hydro electricity generating capacity by 2020 along with increasing generation from natural gas; (4) beyond 2020, a sustained lift in distributed solar with storage and offshore wind; (5) broader adoption of coal import taxes; and (6) improved grid efficiency (e.g. India). China peaks by 2016 and recent declines in the US and European markets accelerate: In the IEEFA “low-‐coal demand” scenario, US thermal coal demand will continue to fall as a result of energy efficiency, natural gas, and renewables; relative to 2013 levels, annual US demand will fall 16% by 2020 and 34% by 2035. Europe’s tighter emission and energy efficiency standards will continue thermal coal’s decline. China's thermal coal demand will peak in 2016, and by 2020 the country will transition from the world’s largest net importer to a net exporter of thermal coal. Demand Japan is also likely decline this decade. The only remaining growth markets for thermal coal will be India, Korea, Taiwan and the ASEAN nations. Significant impacts for exporters of seaborne coal: Given that seaborne coal imports are usually the higher cost, marginal source of supply, a downturn in global demand is likely to hit the seaborne market hardest. IEEFA forecasts seaborne thermal coal demand will average 850Mtpa over 2013-‐2035, down 15% from current peak levels. •
•
There is an increasing debate about whether global thermal coal is in a deep cyclical downturn or structural decline. The steep decline in share prices for listed coal miners over the last three years – with the Bloomberg Global Coal Index of 32 major coal miners down 50% over this period – indicates how the global equity market views the situation. IEEFA is firmly of the view that thermal coal has entered structural decline. Global thermal coal demand will peak by 2016, coinciding with a peak in China’s domestic thermal coal consumption. IEEFA forecasts global thermal coal demand over 2013-‐2020 will be flat at best, and decline 0.1% annually over 2020-‐2035. 16
See our companion paper, Carbon Tracker Initiative (CTI) and Institute for Energy Economics and Financial Analysis (IEEFA), Thermal coal demand: comparing projections and examining risks, September 2014, http://www.carbontracker.org. 22 Sep 2014 16 Key drivers of this transition include: • Energy Security: Is a key motivator of countries energy policy, particularly when most major economies are critically dependent on fossil fuel imports. IEEFA views the strategic energy sector initiatives to diversify fuel supply towards domestic renewable capacity (on and offshore wind, distributed and utility-‐scale solar, hydro) as playing a key role to improving energy security in Japan, China, India, South Africa, the UK and Germany. • Energy Efficiency: From 2010-‐2013 Japan set the benchmark for rapid improvements in energy efficiency; despite 1% per annum real GDP growth, over this period Japan reduced total electricity demand by 12% – a reduction of electricity demand per unit of real GDP of 5% pa. Henceforth Energy efficiency will play a far larger role globally in curtailing demand. • Renewable Energy: As costs continue to fall, IEEFA forecasts a continued acceleration in the deployment of renewable energy. With 116GW of solar, wind and hydro-‐electricity capacity installed in 2012, rising to 120GW in 2013, this follows a CAGR of 10% since 2007. We expect this to continue, with 1,000GW of new renewable capacity globally by 2020. Energy demand trends – top global electricity markets Our global thermal coal demand analysis reviews the growth trends of the 20 largest countries in terms of population, GDP, coal consumption and/or electricity demand. Below we summarize recent developments for 12 of the largest electricity systems in the world, comparing electricity intensity, real GDP growth and electricity growth since 2000 to give a base historic growth rate. To this we provide an evaluation of energy intensity and economic transition; we also evaluate (1) current and likely renewable energy, gas, nuclear and hydro electricity generation plans; and (2) the impact of key regulations and emissions caps/taxes on coal-‐fired power generation. Figure 1: Overview of global thermal coal demand in IEEFA scenario, 2010-‐2035 (Million tonnes) Note: Excludes lignite. Source: IEEFA, IEA 22 Sep 2014 17 Table 2 Country-‐level estimates of thermal coal demand in the IEEA low-‐demand scenario, 2010-‐2035 (Million tonnes) Mt CAGR CAGR 2013-‐20 2020-‐35 OECD Total 1,477 1,401 1,229 1,159 1,109 1,057 -‐1.9% -‐1.0% Americas Total 919 818 693 636 591 551 -‐1.8% -‐1.5% Mexico 15 16 17 18 19 20 1.0% 1.0% Canada 34 27 25 23 22 21 -‐1.0% -‐1.2% US 862 765 641 585 542 502 -‐2.5% -‐1.6% Chile 8 10 9 9 8 8 -‐1.0% -‐1.0% Europe Total 273 291 253 238 221 207 -‐2.2% -‐1.3% Germany 43 41 36 36 33 29 -‐2.0% -‐1.3% France 13 13 11 11 10 10 -‐2.0% -‐1.0% UK 45 55 35 29 24 21 -‐6.0% -‐3.5% Italy 17 20 18 17 15 14 -‐1.5% -‐1.5% Poland 85 76 70 67 64 61 -‐1.0% -‐1.0% Turkey 19 22 26 28 30 31 2.5% 1.2% Other-‐Europe 51 65 56 51 46 41 -‐2.0% -‐2.0% Asia-‐
Total 285 292 283 285 296 299 -‐0.3% 0.4% Oceania Japan 128 136 99 85 77 69 -‐4.5% -‐2.3% Korea 93 97 127 145 166 177 4.0% 2.2% Australia 62 57 55 53 52 51 -‐0.5% -‐0.5% NZ 2 2 2 2 2 2 -‐1.0% -‐1.0% Non-‐OECD Total 3,574 4,208 4,361 4,442 4,468 4,456 0.5% 0.1% Non-‐
Russia 98 111 137 155 171 180 3.0% 1.8% OECD South Africa 186 184 196 199 196 184 0.9% -‐0.4% Other Non-‐
158 188 224 247 266 286 2.5% 1.7% OCED Asia Total 3,116 3,706 3,788 3,826 3,820 3,791 0.9% 0.0% China 2,349 2,833 2,736 2,654 2,537 2,436 -‐0.5% -‐0.8% India 565 657 755 810 853 876 2.0% 1.0% Pakistan 6 5 6 7 9 9 3.0% 2.7% Taiwan 58 56 74 84 96 102 4.0% 2.2% Indonesia 58 65 91 114 137 155 5.0% 3.6% Philippines 13 21 30 37 45 51 5.0% 3.6% Vietnam 26 26 36 45 54 61 5.0% 3.6% Malaysia 23 26 37 46 55 63 5.0% 3.6% Thailand 17 16 22 28 34 38 5.0% 3.6% Latin America Total 16 18 17 16 15 15 -‐1.2% 1.0% -‐ Brazil 9 11 10 10 9 9 -‐1.0% -‐1.0% Other non-‐
7 7 7 6 6 6 -‐1.0% -‐1.0% OCED Americas World Total 5,051 5,610 5,590 5,602 5,577 5,513 0.0% -‐0.1% Note: Excludes lignite. Source: IEEFA, IEA 22 Sep 2014 2010 2013 2020 2025 2030 2035 18 Benchmarking against the International Energy Agency (IEA) The world's most referenced projections of long-‐term energy demand trends come from the International Energy Agency (IEA), the world’s most referenced energy projections. The IEA’s principal document, the World Energy Outlook (WEO), examines the energy trends to 2035 under three different scenarios17: • Current Policies Scenario: A scenario that takes into account “only those policies and measures affecting energy markets that were formally enacted as of mid-‐2013.” The purpose of this scenario is to illustrate both the consequences of inaction and makes it possible to evaluate the potential implications of additional policy measures. • New Policies Scenario: The central scenario of the 2013 World Energy Outlook. In addition to assuming the incorporation of government policies and measures adopted as of mid-‐
2013, the New Policies Scenario also takes into account “other relevant commitments that have been announced, even when the precise implementation measures have yet to be fully defined.” This scenario takes a “cautious view as to the extent to which these commitments will be implemented.”18 • 450 Scenario: This scenario shows a global energy sector on a trajectory with a “near 50% chance of limiting the long-‐term increase in the average global temperature to two degrees Celsius (2°C).” Up to 2020, the 450 scenario assumes the full implementation -‐ more vigorous policy action than the New Policies Scenario therefore -‐ of commitments under the Cancun Agreements made in 2010. After 2020, OECD countries and other major economies are assumed to set “economy-‐wide emissions targets for 2035 and beyond to collectively ensure an emissions trajectory consistent with stabilization of the greenhouse-‐gas (GHG) concentration at 450 parts per million.” The figure below illustrates IEA projections for global thermal coal demand through 2035 under the three different scenarios outlined above and also includes, for comparison, the IEEFA demand projection. 17
IEA, WEO 2013, 36, 645. A full explanation of the assumptions made for each region in each scenario can be found in the IEA, WEO 2013, 646-‐655. 22 Sep 2014 19 18
Figure 2: Projected global thermal coal demand -‐ IEA vs. IEEFA, 2013-‐2035 (million tons of coal equivalent) Source: IEA, IEEFA Note that the IEEFA forecast for 2035 global thermal coal demand is 16.7% below the IEA New Policies Scenario estimate.19 Relative to 2013 coal demand, this presents a very different trajectory. Whereas the most recent IEA New Policies Scenario estimate assumes 18% growth in thermal coal demand over the next 22 years, IEEFA forecasts an absolute decline of 2% or 100Mtpa from 2013 levels. Key points of difference to the IEA reflect IEEFA’s assumption of: 1. Lower forecasts for real GDP growth in China and India; 2. A longer assumed useful life assumption for renewable generation capacity; 3. Greater technology advances driving higher capacity utilization rates for wind and solar; 4. Greater capital cost reductions for onshore wind and solar energy driving high installation rates; 5. Taxes at coal’s point of use have seen a material step up in 2014; 6. A faster removal of fossil fuel subsidies; and 7. IEEFA’s projections assume the US Clean Energy Plan is enacted largely as proposed. The above differences are partly a result of timing. The New Policies Scenario is the IEA’s central scenario as set in third quarter 2013. The thermal coal forecasts presented by IEEFA incorporate a number of new developments over 2014 that are yet to be incorporated into the IEA’s annually revised forecasts. IEEFA expects material changes to the assumptions underpinning the IEA’s central 19
Converting from million tons of coal equivalent to million tons, IEEFA has projected 2035 demand of 5,513 Mt versus the IEA New Policies Scenario projection of roughly 6,614 Mt. 22 Sep 2014 20 premise when the 2014 edition is published, many of which reduce electricity and / or coal consumption expectations. China’s coal demand •
•
•
•
•
•
China consumed close to 50% of the world’s total coal production in 2013. Consumption of thermal coal has seen a CAGR of 8% since 2000. China’s thermal coal demand growth rate declined in 2012 and again in 2013 to average 4% annual growth, half the rate of the previous decade. Further, coal import and production data to date in 2014 implies an unprecedented decline in coal consumption occurred most recently. IEEFA forecasts China’s thermal coal demand will peak in 2016 and gradually decline thereafter. This will have profound implications for the seaborne coal markets, given China accounted for over 20% of total thermal coal imports in 2013. We forecast that China will potentially become an opportunistic net exporter of thermal coal by 2020. Our forecast for slowing demand reflects a combination of a slowing in the rate of real GDP growth combined with a continued program of energy efficiency, plus the structural transformation of China’s economy away from more energy intensive basic and heavy industry towards a service-‐based economy. China’s absolute focus is on energy security through increased system diversity. This drives increased investment in power across the board, everything but coal. Dramatic expansions of hydro electricity and wind capacities are now being supplemented by an increasing installation rate of solar, gas, biomass and most recently nuclear. Increased supply of non-‐coal based electricity plus reduced demand growth means a forecast peak in thermal coal demand by 2016. Figure 3: China’s Electricity Market – Production Waterfall, 2013-‐2020 (TWh) 22 Sep 2014 Source: IEEFA 2014 analysis 21 Trends in US coal •
•
•
•
•
From 2000 to 2013, US thermal coal consumption is down 101Mtpa to 765M metric tonnes. Energy efficiency gains mean total US electricity consumption is up only 0.2% pa over 2004-‐
2013. We see scope for energy efficiency gains to be significantly stepped up. Coal-‐fired electricity production is down 2.4% pa over 2004-‐2013. Coal-‐fired power capacity closures are forecast to cut US domestic thermal coal demand by another 124Mtpa or 16% by the end of this decade. Expanded renewable energy and gas-‐fired electricity generation will increasingly replace what has traditionally been a coal-‐fired electricity system. The chart below details our forecast for changes to the American electricity sector by 2020 relative to the 2013 base. Figure 4: America’s Electricity Market – Production Waterfall, 2013-‐2020 (TWh) Source: IEEFA 2014 analysis India’s coal demand The points below summarize our conclusions on the outlook for India’s thermal coal demand. Note that, due to data limitations, India’s thermal coal production (currently ~7% of global production) is not included in our supply analysis. For more discussion see our methodology section below. •
India is forecast to see real GDP growth of 5.5% pa through to 2020. Energy efficiency gains of 1.0% pa and transmission and distribution loss reductions of 1.0% pa would lower electricity system growth to a net 3.5% pa. 22 Sep 2014 22 •
•
•
•
•
The Government of India (GoI) targets increasing renewable energy capacity from 32GW today to 72GW by 2022. Coupled with expanded hydro-‐electric capacity and increased imports of hydro-‐electricity from Nepal and Bhutan this will drive a significant diversification of the Indian electricity system. However, much more is commercially viable. The GoI is contemplating a fivefold boost to annual wind installations to 10GW. This would be a major policy change that would significantly reduce coal demand growth. In conjunction with improved railway productivity and capacity, Coal India Ltd targets a 50Mtpa expansion of domestic coal production through to 2020. Even assuming only a 20Mtpa expansion of domestic thermal coal supply, this will be sufficient to meet India’s thermal coal needs without imported coal gaining any further market share. Until India delivers a huge electricity system reform, in IEEFA’s view sustainable economic growth will not occur. Electricity utilities can’t keep losing tens of billions of dollars annually on unfunded subsidies of electricity. Utilities can’t keep losing 25% of all electricity generated. India can’t keep building new thermal capacity when existing capacity is idle due to lack of fuel supply. Projects can’t take 5-‐10 years to complete without prohibitive financing costs killing off the economics entirely. IEEFA does not see India delivering as the great white hope of the export coal industry. Figure 5: India’s Electricity Market – Production Waterfall, 2013-‐2020 (TWh) Source: IEEFA 2014 analysis 22 Sep 2014 23 20
3. Recent financial trends in the global coal industry •
Coal prices are down 40% since 2011: Over the past three years coal prices around the world have fallen sharply. The current free-‐on-‐board Newcastle spot price (a key benchmark for Pacific export markets) is 40% below average 2011 prices. Over this period major coal consumers such as the US and China have seen domestic coal prices fall by a similar amount. Though the specific causes vary by market, generally coal prices are under pressure due to (1) lower-‐than-‐expected growth in coal demand (or turning negative) due to more energy efficiency, competition from other electricity sources, and regulations to limit air pollution from coal (all amid a context of low-‐to-‐moderate economic expansion); and (2) in export markets and China's domestic market, robust supply growth as projects undertaken in response to high prices of a few years ago begin to produce. •
Undermining profit margins for coal producers: Current prices are eliminating profit margins for a growing number of coal producers. In the seaborne export market, we estimate current spot prices to be below the “cash costs” of production for nearly one-‐half of total capacity and to be below the “breakeven coal price” (which includes capital costs and economic returns) for two-‐thirds of total capacity. Over half of China’s coal producers have cash costs in excess of domestic Chinese spot prices, and throughout the US higher-‐
cost miners (particularly in regions such as Central Appalachia) are currently producing at a loss. •
… and returns for investors in listed coal companies: The current stressed state of coal markets is reflected in the financial performance of publicly-‐traded coal companies. From Aug 2011-‐2014, the Bloomberg Global Coal Index of 32 major publicly-‐traded coal companies declined by 56% while the MSCI World Index (a broad market benchmark) increased by 31%. In the US, over two dozen coal producers have filed for bankruptcy since 2012 (including two companies with over $1 billion in assets); during this period US coal companies have also seen widespread executive turnover, with 11 major producers replacing a CEO, Chairman, or other senior executive. •
Reckoning with a $200+ billion build-‐up in coal assets: We survey 83 major publicly-‐listed coal producers, including 60 that produce thermal coal. Since 1990, capital expenditures (capex) and acquisitions by these firms have increased their combined net fixed assets by $214 billion (in real terms); thermal coal assets – chiefly in China and the US – account for over 70% of this increase (i.e. $154 billion). •
Thermal coal producers beginning to reduce capex? Crucial engagement issue for investors: Recent investments in thermal coal, however, generally have generated weak returns for shareholders. The reality of weak returns – combined with a need to hoard cash in order to maintain already weak credit ratings – provide the context for the 60 thermal coal producers in our sample modestly reducing their combined capex from 2012 to 2013. Note that combined capex for this group increased each year from 2000 to 2012. Cash allocated to the combined 2013 capex of these 60 firms, however, remained roughly 3 times the cash returned to stockholders via dividends and share repurchases. This observation 20
See our CTI/ETA companion report, “King Coal” disappoints investors: recent financial trends in global coal mining, September 2014, http://www.carbontracker.org. 22 Sep 2014 24 2014 underscores how engaging with thermal coal producers on capital management decisions ought to be a top priority for investors concerned with returns, especially in the context of carbon asset risk. •
Among diversified miners, Glencore Xstrata buys thermal coal while BHP and Rio sell: As a complement to our analysis of pure-‐play coal producers, we also examine the coal operations of four large diversified mining companies (Anglo American, BHP Billiton, Rio Tinto, and Glencore Xstrata). We note an emerging schism in this group between buyers and sellers of thermal coal assets. Both prior and subsequent to its 2012 $45 billion acquisition of Xstrata (which, at the time of acquisition, generated 25% of its revenue from thermal coal), Glencore has been snapping up thermal coal assets in South Africa, Australia, and elsewhere. In many cases, the seller of those assets has been either Rio Tinto or BHP Billiton. BHP, for its part, is in the process of trying to spin off its remaining South African thermal coal mines into a separate entity (while also notably shifting its coal-‐related capex away from thermal and toward metallurgical coal). Buying assets at low valuations can be a promising (albeit risky) strategy to generate returns, particularly if the assets in question have low production costs. Analysis in our companion reports, however, concludes that thermal coal is going into structural decline and therefore diversified companies will best serve shareholder interests by reducing exposure to thermal coal. Investors in such companies ought to prioritize engaging with management to understand company plans regarding capex and M&A related to thermal coal. Declining prices, squeezed margins, and executive turnover: overview of recent financial trends in the coal industry Recent years have been challenging to the global coal industry. Since at least 2011 the global coal sector has shown significant financial underperformance. The most striking feature of the last few years has been the sharp decline in prices for both thermal and metallurgical coal. Focusing on the roughly 1 billion tonne21 market for thermal coal exports (in 2013 equal to 18% of the global thermal coal market), the chart below shows average annual prices for Newcastle export thermal coal, a key benchmark price in the Pacific region.22 Having fallen sharply and then rebounded from 2008-‐2011, since 2011 Newcastle prices have been in steady decline. The August 2014 Newcastle spot price of $68/tonne is down over 40% from the average 2011 price of $121/tonne (with the year-‐to-‐date average 2014 price down nearly 40% as well). The chart below also shows the spot price of coal from the US Central Appalachian region (CAPP), a key price for coal supplied to thermal power plants in the eastern US. The August 2014 CAPP spot price of $60/ton is down over 30% from the average 2011 price of $87/ton (and down 66% from the average 2008 price of $118/ton). Forward curves show 2018 Newcastle and CAPP prices 10-‐20% above current spot prices but well below the high price levels observed in 2008 and 2011. 21
Throughout this report, “tonne” refers to metric tonnes and “tons” to short tons. Note that 1 metric ton = 1.10 short tons. 22
FOB Newcastle is a price for thermal coal exported out of the port of Newcastle on Australia’s eastern coast and typically shipped to China. 22 Sep 2014 25 2014 Figure 6: Annual average prices for Newcastle export steam coal and US Central Appalachian Coal (CAPP), 2000-‐2018 $140/t
$120/t
$100/t
$80/t
$60/t
$40/t
$20/t
$0/t
2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018
Newcastle F OB ( $/t)
Newcastle F OB F utures ($/t)
CAPP ($/t)
CAPP F utures ($/t)
Note: Values shown are annual averages of free on board (FOB) weekly prices. Newcastle prices in US$/metric tonne and US prices in $/short ton. Newcastle energy content is 6000 kcal/kg; CAPP energy content is 12,500 Btu/lb (i.e. ~6900 kcal/kg). 2014 Newcastle price is averaged to end in June; for CAPP, it is average of remaining 2014 futures prices. Source: Platts, BP, Bloomberg LP, CTI/ETA analysis 2014 The price declines described above have also occurred in other regional coal markets23 as well as in the market for metallurgical coal (where prices have also declined more than 40% since 2011). Though the specific causes vary by market, generally speaking thermal coal prices are under pressure due to (1) growth in coal demand slowing (or turning negative) due to more efficient use of energy, competition from other energy sources, and regulations to limit air pollution from coal (all amid a context of low-‐to-‐moderate economic expansion)24; and (2) in export markets, robust supply growth as projects undertaken in response to high prices of a few years ago begin to produce. Paragraphs below provide more detail on these trends. Declining thermal coal prices eroding profit margins The decrease in coal prices since 2011 has caused profit margins for coal producers to diminish or, in some cases, disappear entirely. Using mine-‐level data from Wood Mackenzie’s Global Economic Model (GEM) database25, the figure below shows a 2014 supply curve for export thermal coal production capacity (including lignite). For over 1,000 mines with the potential to produce export thermal coal, the blue line shows each mine’s energy-‐adjusted “cash costs ”of production26; the 23
For coal imported into Northwest Europe, the price averaged at $147/t in 2008 and $122/t in 2008, versus $73/t today and a 2018 forward curve price of $87/t. BP, BP Statistical Review of World Energy June 2014, “Coal: prices", 2014, http://www.bp.com/statisticalreview. 24
For more discussion of these trends, see our companion paper, Carbon Tracker Initiative (CTI) and Institute for Energy Economics and Financial Analysis (IEEFA), Thermal coal demand: comparing projections and examining risks, September 2014, http://www.carbontracker.org. 25
Wood Mackenzie's Global Economic Model (GEM) coal database includes detailed cost data for 1,200+ mines,http://public.woodmac.com/content/portal/energy/highlights/wk3_Nov_13/Global%20Economic%20
Model%20Coal.pdf 26
In this case, costs have been standardized to a net-‐as-‐received basis of 6,000 kcal/kg. Note that, in Wood Mac’s Global Economic Model, “cash costs” include both variable and fixed costs. For example, in Australia take-‐or-‐pay infrastructure costs are fixed for many operators, and these are incorporated into the cash cost estimates above. Likewise the component of a BECP over and above total cash cost is not necessarily a fixed 22 Sep 2014 26 2014 orange line shows each mine’s “breakeven coal price” (BECP), a measure – taking into account both cash and capital costs as well as production over the lifetime of the mine – of the price that will yield the mine owner a net present value of zero assuming a 10% real discount rate. BECP figures are standardized to a “Newcastle-‐equivalent price,” which takes into account differences in energy content as well as differences in the cost of transport for export mines in different countries.27 The dashed lines intersecting the cash-‐cost and BECP curves represent, as of August 2014, the Newcastle spot price (grey line)28 and 2018 forward price (purple line). Figure 7: Significant potential production uneconomic at current prices -‐ 2014 potential export thermal coal by cash cost and breakeven price (BECP) level, Mtpa Note: BECP is breakeven coal price; NAR is net-‐as-‐received Source: Cost and supply data from Energy Economics, using Wood Mackenzie Global Economic Model; price data from Bloomberg LP, and CTI/ETA analysis 2014 The August 2014 Newcastle spot price of $68/t is below the Newcastle-‐equivalent BECP for 72% of export thermal coal production capacity (i.e. 1067 Mtpa); for mines in this group, income from selling at a price of $68/t is insufficient to earn the mine owners a 10% return on their investment. The figure also illustrates the August 2014 Newcastle spot price to be below the cash costs of production for 47% of export thermal coal production capacity (i.e. 697 Mtpa); for mines in this group, a price of $68/t is insufficient to cover even the cash costs of production. Assuming that the Newcastle spot price were to increase to the 2018 forward price of $82/t, this would still fail to meet the BECP requirements for 30% of production capacity (i.e. 445 Mtpa) and fail to cover cash cost – in the economic long run (prior to investment), this capital component is fully flexible. In the short run, where this increment represents sustaining capital, it is also likely to be variable. 27
For more discussion of this, see the methodology section of our companion paper, Carbon Tracker Initiative and Energy Transition Advisors, Carbon Supply Cost Curves: Evaluating Financial Risk to Coal Capital Expenditures, September 2014, http://www.carbontracker.org. 28 Since August thermal coal spot prices have not increased. On September 3rd, a spot contract for Australian thermal coal was concluded at $66.85/t (FOB, net calorific value of 6,000kcal/kg). This represented the lowest price in five years (i.e. since September 11th, 2009 when a deal was realized at $66.50/t). 22 Sep 2014 27 2014 costs for 11% of production capacity (163 Mtpa).29 The table below provides a country-‐level breakdown of unprofitable potential export capacity at a price of $68/t. On both the cash cost and BECP curve, a majority of production capacity over $68/t exists in China. As the world’s largest importer of thermal coal, China currently exports relatively little thermal coal (with the country having become a net importer in 2009). That said, the mines represented on the curve above do have the capacity to produce export-‐grade thermal coal (should prices justify it). For reference, note that as of 2005 China was exporting nearly 70 million tonnes of thermal coal (33 million tonnes of net exports), or roughly the same amount as South Africa has exported for much of the past decade. China’s sizeable imports of thermal coal are a relatively recent phenomenon and reflect not just growing demand but also discrepancies between domestic and international prices resulting from, among other things, rail transportation bottlenecks within China and appreciation of China’s currency against the currency of coal exporters such as Indonesia.30 None of this, however, rules out the possibility of China – should the economics justify it – ramping (back) up its exports of thermal coal. Figure 8 China exports and imports of thermal coal, 2005-‐2012 (Mt) 250
231
200
150
Mt
150
126
104
100
66
50
30
45
59
57 51
45 42
22
20
18
2009
2010
2011
9
0
2005
2006
2007
2008
Imports
2012
Exports
Source: IEA, IEEFA, CTI/ETA analysis 2014 Excluding the 607 Mt of capacity in China, the percentage of total potential export production with 29
That a 21% increase in the spot price can cause the amount of “out-‐of-‐the-‐money” potential production capacity to decline by 58-‐77% illustrates the implications of a flat (i.e. price-‐elastic) export supply curve. 30
Constrained rail transport from China’s coal-‐producing northern provinces increases the cost of transporting coal to consumers in the southern and coastal provinces; as a result, particularly given the recent appreciation of China’s currency, such consumers can often source coal internationally at prices lower than China’s domestic coal prices. Citi, for example, notes that “truck deliveries of coal make up a large portion of the delivered cost of coal because of multiple tolls and high diesel fuel prices, among other cost components. Larger miners in China, along with the continued reduction in bottlenecks in the transportation network, could push out foreign coal imports.” Citi, “The Unimaginable: Peak Coal in China,” Sep 4 2013, 6. 22 Sep 2014 28 2014 cash costs above the current spot price is 27%; the percentage of total production with BECPs above the current spot price is 61%. Perhaps most striking is the rightmost column in the table, showing production capacity above $68/t (Newcastle-‐equivalent BECP) as a share of each country’s total export thermal coal production capacity. In every country save for South Africa, this share is near or above 50% -‐ and, in Colombia and Russia, approaches 90%. Table 3: Breakdown by country of potential 2014 export thermal coal production capacity above $68/t (Aug 2014 Newcastle FOB spot price) Cash Costs Newcastle-‐equivalent BECP Mt % of total Australia China Colombia Indonesia Russia South Africa USA 61.0 461.3 1.7 70.7 82.5 2.0 10.7 9% 66% 0% 10% 12% 0% 2% % of country export capacity 31% 76% 2% 20% 86% 3% 27% ROW Total 8.4 698.3 1% 100% 30% 47% Mt % of total 95.9 534.5 75.7 201.8 85.6 29.7 26.4 9% 50% 7% 19% 8% 3% 2% % of country export capacity 49% 88% 85% 58% 89% 39% 67% 22.2 1071.8 2% 100% 80% 72% Note: Values shown reflect potential capacity, rather than actual exports. China, for example – currently the world’s largest net importer – will in 2014 likely export very little thermal coal. For ”% of country export capacity” columns, values in “Total” row are weighted averages. Source: Energy Economics, using Wood Mackenzie Global Economic Model and CTI/ETA analysis 2014 Note that the current situation of most export thermal coal mines is slightly different from that suggested by the above comparisons. This is because 60-‐85% of thermal coal exports (depending on the region) are traded at a price set in multi-‐month to multi-‐year contracts, as opposed to at spot prices during a given month. Because resetting of the prices in these contracts tend to lag changes in the spot price, during periods of sustained price declines (as has been occurring since 2011) contract prices may be above the current spot price. Even longer-‐term contract prices, however, would still be unprofitable for a large chunk of potential production.31 Moreover, the recent decline in spot prices appears to be reflected in contract prices. For example, on September 3rd the contract price for South African thermal coal was fixed at $68/t (the lowest price since December 8th, 2009, when a contract was signed at $66.25/tonne). Finally, though the exact figures differ, the trend described for export thermal coal of declining margins and a growing portion of “out-‐of-‐the-‐money” production has in recent years also occurred 31
As of August 2014 a contract linked to the average last-‐twelve-‐months (LTM) Newcastle FOB spot price would show a price of $73/t; this price would still fail to cover BECP requirements for half of export thermal coal production capacity (i.e. 726 Mtpa) and fail to cover cash costs for 40% of production capacity (593 Mtpa). 22 Sep 2014 29 2014 in the major domestic markets for coal (e.g. China and the US) as well as the metallurgical coal market. Sections below explore these markets in more detail. Financial impacts of declining margins After delivering superior returns in the early 2000s on the back of sharp increases in coal prices, recent returns from coal mining stocks have badly lagged the broader market. The Bloomberg Global Coal Index measures the performance of the coal sector by tracking the share prices of 32 large pure-‐play coal producers. The figure below compares the 5-‐year performance of this index against the MSCI World Index (a proxy for overall market returns) and the MSCI World Energy Index (which, their larger market capitalizations relative to coal companies, is heavily weighted toward oil and gas companies). While since 2009 the overall market has increase in value by 64% (and the overall energy sector by nearly 50%), the coal sector has declined in value by more than 50%. Figure 9: Bloomberg Global Coal Index vs. the MSCI World Index and MSCI World Energy Index, Aug 2009 -‐ Aug 2014 180
164.1
Index Value (rebased to 100)
160
140
149.6
120
100
80
60
47.6
40
20
Bloomberg Global Coal index MSCI World Energy Index
MSCI World Index
Aug-‐14
May-‐14
Feb-‐14
Nov-‐13
Aug-‐13
May-‐13
Feb-‐13
Nov-‐12
Aug-‐12
May-‐12
Feb-‐12
Nov-‐11
Aug-‐11
May-‐11
Feb-‐11
Nov-‐10
Aug-‐10
May-‐10
Feb-‐10
Nov-‐09
Aug-‐09
0
Source: Bloomberg LP, CTI/ETA analysis 2014 Though financial performance of the coal sector over the last five years has been particularly poor, the table below shows the coal sector to have also underperformed the broader market on a 10-‐
year-‐, 3-‐year, and year-‐to-‐date time scale.32 Current price-‐to-‐earnings (P/E) ratios – one measure of market sentiment on the potential for future growth in earnings – suggest continuing market skepticism about future returns in the coal sector. With “earnings” here relating to one-‐year forward earnings, as of August 2014 the Bloomberg Global Coal Index displayed a P/E ratio of 7X versus a P/E ratio of 16X for the MSCI Energy Index and 18X for the MSCI World Index. The above data points suggest that financial markets expect continuing hard times for coal. 32
Partly as a result of fluctuations in commodity prices, coal stocks have also been significantly more volatile than the broader market; since its inception in August of 2003, the Bloomberg Global Coal Index has had annualized volatility of 24%, versus 20% for the MSCI Energy Index and 14% for the MSCI World Index. 22 Sep 2014 30 2014 Table 4: Comparing returns for the Bloomberg Global Coal Index, MSCI World Index, and MSCI World Energy Index Bloomberg Global Coal Index MSCI World Energy Index
MSCI World Index
YTD
-‐1.1%
8.0%
2.7%
1 year
-‐0.1%
15.2%
11.9%
3 year
-‐56.2%
13.9%
31.5%
5 year
-‐50.7%
49.6%
63.3%
10 year
since inception (8/12/2003)
51.6%
108.3%
66.1%
136.6%
167.6%
91.8%
Source: Bloomberg, CTI/ETA analysis 2014 One consequence of sustained financial underperformance has been widespread turnover within the executive ranks of coal companies. From January 2012 to March 2014, the figure below annotates the trend of the SNL coal price index) with descriptions of management changes at major US coal companies. For reference, in the next section we undertake detailed financial analysis of a sample of 83 coal companies that includes 15 US companies; of these 15 companies, over the past two and a half years, six of them have replaced a CEO or other senior executive (e.g. President). Moreover, in at least one case, losses related to coal by a major diversified mining company are thought to have contributed to a CEO’s departure.33 Note that this group of six companies includes four of the five largest US coal producers (Peabody Energy, Alpha Natural Resources, Arch Coal, and CONSOL Energy). The growing unwillingness of corporate boards and investors to endure continued coal-‐related losses highlights what might be termed the “CEO risk premium” related to coal. As examples of loss-‐
making investments in new coal mines continue to spread, it is plausible that boards and shareholders of companies will significantly decrease their tolerance for investment decisions that assume continued unrealistically high coal prices. The concept of the "CEO risk premium" is directly applicable to much of the detailed company-‐level financial analysis below. Figure 10: Recent management changes at US coal companies 33
Rhiannon Hoyle, "Rio Tinto to Sell Mozambique Coal Assets for $50 million," Wall Street Journal, July 30 2014, http://online.wsj.com/articles/rio-‐tinto-‐to-‐sell-‐mozambique-‐coal-‐assets-‐for-‐50-‐million-‐1406704712. 22 Sep 2014 31 2014 Source: SNL Financial Detailed financial analysis of publicly-‐listed coal-‐mining companies To examine a broader cross-‐section of firms than the 32 that are contained in the Bloomberg Global Coal Index, we survey 2000-‐2013 data on companies that the Industry Classification Benchmark (IBC) system groups into the Coal subsector.34 Out of all the companies in this category, we focus on 83 that (as of August 2014) have a market capitalization above $200 million.35 We classify companies into separate groups depending on whether they produce thermal coal, met coal, or both. Companies that produce both are classified as “met” or “thermal” only in the event that one of the two segments accounted for 75% or more of total 2013 coal revenue; otherwise the company is classified as “balanced.” The table below provides a breakdown of the companies in our universe. Following the theme of our companion report36, our focus throughout is on the thermal coal market. Data on metallurgical coal producers is provided as a basis for comparison and is generally not explored in detail. We note that substitutes for met coal are not generally available and so demand follows steel/iron ore demand. Thermal coal is easily substitutable in power markets as discussed. Note that this universe excludes coal producers that the IBC system classifies as diversified mining and metals companies. We review a sample of the largest coal-‐producing diversified mining companies in the next section. Table 5: Summary statistics on universe of coal companies 34
Basic Materials (industry) >> Basic Resources (supersector) >> Mining (sector) >> Coal (subsector). http://www.icbenchmark.com/Site/ICB_Structure 35
Though this threshold may seem low, note that the median market cap for firms in our sample is $1.2 billion; only eight companies have a market cap above $5 billion, and only three have a market cap above $10 billion. 36
CTI and ETA, Carbon Supply Cost Curves: Evaluating Financial Risk to Coal Capital Expenditures. 22 Sep 2014 32 2014 # of Companies
Combined Market Cap ($bn)
Thermal Coal Companies
44
$152.5
Met Coal Companies
23
$27.3
Balanced Coal Companies
16
$35.6
83
$215.4
Total
Source: Bloomberg LP, CTI/ETA analysis 2014 Our universe of listed companies includes several that are majority-‐owned by local or national governments (e.g. Coal India, various Chinese producers). That said, the figure below illustrates that focusing on listed companies results in the underrepresentation of coal production capacity in non-‐
OECD countries.37 As completely unlisted state-‐owned firms generally finance projects via funds from internal operations, however -‐ as opposed to via debt and equity from banks and capital markets -‐ trends related to listed firms are the relevant focal point for investors interested in carbon asset risk related to coal. Figure 11: Ownership structure of hard coal production capacity, 2012 Source: Wood Mackenzie databases; IEA analysis Revenues, margins, and returns on investment/shareholder equity The figure below depicts annual combined revenues by producer category for the companies in our universe. Note that part of the increase here reflects new firms coming into our sample. In 2000 only roughly half of these entities existed as publicly-‐traded companies, with the other half emerging in the public markets between 2000 and 2008 (an active time for coal-‐related initial public offerings). From 2008-‐2011, however, combined revenues for each producer category nearly doubled as a result of increasing production and the post-‐financial crisis rebound in coal prices. Relative to 2011 revenues, however, combined 2013 annual revenues were 10% lower for balanced producers, 17% lower for met producers, and only 11% higher for thermal producers. 37
Note, though, that export-‐focused producers outside the OECD such as Indonesia, Colombia, and South Africa have a high degree of listed private-‐sector ownership. IEA, Special Report: World Energy Investment Outlook, 57, Figure 2.4, 2014. 22 Sep 2014 33 2014 Figure 12: Revenues of coal producers, 2000-‐2013 Annual Revenue (billion USD)
140
120
100
80
60
40
20
0
Balanced
Met
Thermal
Source: Bloomberg LP, CTI/ETA analysis 2014 Note: Sample does not remain constant over this period. In 2000 only half of the universe existed as public companies; data for these companies is progressively added to the sample as it becomes available. Sample nearly entirely complete by 2008. Looking at the 58 companies with available revenue projections for 2014-‐2016, estimates are for roughly flat year-‐on-‐year revenue growth in 2014 followed by single-‐digit growth in 2015 and 2016. Recognizing that annual revenues are now at a higher overall level, this pattern of year-‐on-‐year growth marks a sharp decline from the 2010-‐2012 period, when combined revenues for each producer category grew by an average year-‐on-‐year rate of 22-‐28%. Table 6: Market estimates of year-‐on-‐year revenue growth for coal producers by category, 2014E-‐2016E Balanced (15 companies) Met (15 companies) Thermal (28 companies) 2014E 2015E 2016E 1% -‐3% 0% 8% 7% 7% 2% 7% 5% Note: Data available for only 58 of 83 companies. Source: Bloomberg LP, CTI/ETA analysis 2014 Despite the 40-‐50% decline in met and thermal coal prices from 2011-‐2013, many producers were 22 Sep 2014 34 2014 buffered against even more substantial declines in revenue as a result of (1) continued demand growth; and (2) increased production from new projects begun during periods of high prices (often so-‐called “brownfield” expansions of existing mines).38 More significant than recent declines in revenue, then, have been declines in operating profits. One basic measure of operating profit is earnings before interest and taxes (EBIT); EBIT margin refers to EBIT as a share of revenue. Combining annual EBIT and revenue across each of the three producer categories, the figure below shows annual EBIT margins from 2000-‐2013.39 Note the sharp decline in EBIT margins across all three categories from 2011-‐2013. As of 2013, the combined EBIT margin for each producer category had declined to its lowest point since roughly 2003 (with the average margin for thermal producers slightly below the 2003 level). Figure 13: EBIT margin by producer category, 2000-‐2013 30%
EBIT margin
25%
20%
15%
10%
5%
0%
Balanced
Met
Thermal
Source: Bloomberg LP, CTI/ETA analysis 2014 For the subset of firms with 2014-‐16 EBIT projections, market estimates show EBIT margins trending up slightly for balanced and (eventually) met producers, while holding steady for thermal producers. Table 7: Market estimates of EBIT margins coal producers by category, 2014E-‐2016E Balanced (10 companies) Met (20 companies) Thermal (8 companies) 2014E 2015E 2016E 7% -‐4% 17% 10% 5% 17% 12% 9% 18% Note: Data available for only 38 of 83 companies. Source: Bloomberg LP, CTI/ETA analysis 2014 38
Additionally, as discussed above, due to extensive use of long-‐term contracts in at least export coal markets, prices received by producers tend to lag changes in the spot price, delaying the impact to revenues as a result of declining prices. 39
Taking a market-‐cap weighted average of the EBIT margins of individual companies within each category shows slightly different annual values but a similar trend. 22 Sep 2014 35 2014 The primary driver of declining EBIT margins has been the post-‐2011 40-‐50% decline in spot prices for both met and thermal coal (which, as discussed above, continue to make their way through to long-‐term producer contracts). Additionally, however, producers in many countries have also been experiencing lower margins due to rising costs of production and declining productivity. In Australia, for example, a mining boom and resulting supply chain pressures helped to increase the cost of inputs to coal production (e.g. labor, power, and rail costs) by 7-‐20% from 2006 to 2014 (while also spurring the Australian dollar to appreciate against the US dollar by 5%).40 Moreover, Goldman Sachs estimates that after growing at a +2% CAGR from 1986-‐2001, average productivity of coal miners in the US, Australia, and China declined at a CAGR of 5% from 2002-‐2012.41 Such productivity declines are one reason that these three countries dominate the list of miners (both large and small) that recorded negative EBIT margins for 2013 – though other trends (e.g. the appreciation of the Australian dollar, which harms the bottom line of Australian exporters) also played a significant role as well. Table 8: Firms with negative EBIT margins for 2013 Company HIDILI INDUSTRY INTL DEVELOP ALPHA NATURAL RESOURCES INC RASPADSKAYA WALTER ENERGY INC WHITEHAVEN COAL ARCH COAL INC KINETIC MINES AND ENERGY LTD TAIYUAN COAL GASIFICATION YANCOAL AUSTRALIA LTD DATONG COAL INDUSTRY CO SHANGHAI ACE CO Category Country Market Cap (USD million) 2013 EBIT margin (%) Balanced China 229.6 -‐31.2 Balanced US 710.5 -‐15.7 Met Russia 394.8 -‐13.3 Met US 357.4 -‐9.0 Met Australia 1500.8 -‐8.2 Met US 675.1 -‐5.6 Thermal China 478.6 -‐90.5 Thermal China 586.1 -‐32.9 Thermal Australia 232.4 -‐13.8 Thermal China 1437.6 -‐1.5 Thermal China 614.0 -‐0.4 Source: Bloomberg LP, CTI/ETA analysis 2014 Declining EBIT margins have intensified producer focus on reducing costs as a way to improve profitability. Ironically, however, declining margins -‐ largely a result of low prices -‐ have spurred some producers to increase production as a way to maximize economies of scale and hence lower per unit costs. In the aggregate, however, such strategies work to exacerbate conditions of oversupply that are in part the cause of low margins to begin with. ROIC below WACC signals weak value-‐creation in the coal industry 40
CIBC, "Rio Tinto" 56. Goldman Sachs, "The Thermal Coal Paradox," May 23 2014, 16. 22 Sep 2014 2014 41
36 Declining margins have eroded the ability of coal miners to generate returns for investors. Return on invested capital (ROIC) is a measure of a firm's efficiency at directing its capital toward profitable investments.42 Comparing a company's return on capital (ROIC) with its weighted average cost of capital (WACC)43 can illuminate whether capital has been invested effectively. The figure below illustrates the evolution of ROIC for each producer category from 2000-‐2013. As expected, high (albeit volatile) coal prices from 2003-‐2011 enabled firms to enjoy average ROIC rates of 15-‐20%, versus a global average WACC for the coal sector of around 10%. Post-‐2011, however, declining coal prices and diminished margins have reduced ROIC to at or below the coal sector's global average WACC -‐ a signal of poor value-‐creation (or outright value-‐destruction) for investors. The evolution of Return on Equity (ROE) -‐ a narrower measure than ROIC which focuses just on returns for equity holders -‐ tells a similar story, with average ROE levels declining from 25-‐40% to near or below the coal sector's 10.9% global average cost of equity. Figure 14: Average Return on Invested Capital (ROIC) by producer category, 2000-‐2013 Note: Annual averages are weighted by market cap. Source: Bloomberg LP, CTI/ETA analysis 2014 Uses of cash: capex vs. dividends/buybacks Though in the near term coal prices may rebound from current levels, at least with respect to thermal coal, our companion supply-‐demand analysis casts doubt on the long-‐term viability of prices that exceed $100/tonne (as occurred regularly from 2008-‐early 2012) in both the seaborne export market as well as key domestic markets.44 This suggests a lowered ceiling on thermal coal miners’ ability to generate returns for investors, and strengthens the rationale for companies to reduce capital expenditures (capex) on expanding existing mines or developing new ones. Figure 15: Cumulative growth in net fixed assets by producer category, 1990-‐2013 (billion 2012 USD) 42
ROIC is calculated as (Net income – dividends) / total capital. Weighted average cost of capital measures takes into account a company's cost of equity and cost of debt, as well as its mix between equity and debt. 44
Our long-‐term estimate for the seaborne market, for example, is $75/tonne. 22 Sep 2014 37 2014 43
250
billion USD (2012)
200
150
100
50
0
1990 1992 1994 1996 1998 2000 2002 2004 2006 2008 2010 2012
Balanced
Met
Thermal
Source: Bloomberg LP, CTI/ETA analysis 2014 As a result of capex as well as acquisitions, since 1990 the 83 firms in our sample have increased their combined net fixed assets by $214 billion (in real terms). The 44 companies that we classify as thermal coal producers have accounted for 63% of this total (i.e. $135 billion); adding in thermal assets of firms that we classify as balanced producers would likely push the thermal share over 70% (i.e. $154 billion).45 Moreover, including thermal coal assets for diversified companies and smaller pure-‐play producers would push 1990-‐2013 overall net fixed asset growth closer to $300 billion.46 China has dominated growth in coal assets since 1990, accounting for 67% of the overall total (i.e. $143 billion), with the vast majority of this relating to thermal coal. The US has supplied the second-‐
largest share (20%, or $43 billion), with the rest of the world accounting for 16% (i.e. $29 billion). Figure 16: Cumulative growth in net fixed assets by country, 1990-‐2013 (billion 2012 USD) 45
We assume net fixed assets of balanced producers split evenly between met and thermal; in reality, in most cases thermal assets likely exceed met assets. 46
Goldman Sachs, "The Thermal Coal Paradox," May 23 2014, 16. 22 Sep 2014 38 2014 250
billion USD (2012)
200
150
100
50
0
1990 1992 1994 1996 1998 2000 2002 2004 2006 2008 2010 2012
China
US
ROW
Source: Bloomberg LP, CTI/ETA analysis 2014 The above figures encapsulate the challenge facing thermal coal producers. Since 2000, thermal coal miners have been adding capacity to satisfy a world where global demand for thermal coal was growing at a CAGR of 4%. They must now adjust to a world where we project global demand for thermal coal to be essentially flat through 2025 (i.e. grow at a CAGR of 0.1%) before beginning to decline from 2025-‐2035 at a CAGR of -‐0.2%.47 This transition in the rate of demand growth is undermining opportunities for profitable new thermal coal investment. Additionally, with median free cash flow48 levels sinking below total debt levels, there is a pressure to reduce capex in order to defend credit ratings. As a result of the above conditions, thermal coal miners have throttled down (and, at some point soon, may possibly reverse) the asset growth that has been a defining trend in the coal industry since at least 2000. The figure below illustrates that this process of slowing investment growth has already started. Since 2011 the rolling 4-‐year CAGR of total invested capital by the 44 thermal coal producers in our samples has fallen from 20% to 10% (with balanced and met producers showing a similar trend). Moreover, from 2012 to 2013 the combined capex of these 44 thermal coal producers actually decreased modestly (from $20.3 to $19.4 billion) -‐ the first such year-‐on-‐year decrease since at least 2000. Again, this trend also held across balanced and met producers. Figure 17: Invested Capital (rolling 4-‐year CAGR), 2003-‐2013 47
CTI and IEEFA, Thermal coal demand: comparing projections and examining risks. Free cash flow is calculated as operating cash flow minus capital expenditures. 22 Sep 2014 2014 48
39 Invested Capital (Rolling 4 -‐year CAGR) 60%
50%
40%
30%
20%
10%
0%
2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013
Balanced
Met
Thermal
Source: Bloomberg LP, CTI/ETA analysis 2014 Many thermal coal producers, however, have a backlog of delayed or under-‐study projects waiting to commence construction once thermal coal prices pick up. Moreover, the figure below shows that 2013 annual capex for pure-‐play thermal coal producers remained nearly 3X the return of cash to shareholders via dividends and net share repurchases (i.e. "buybacks”). For balanced producers of both met and thermal coal – who, by volume, include many of the largest coal producers49 -‐ the ratio of capex-‐to-‐dividends/buybacks was even higher (4X).50 The ratio of thermal capex to dividends and buybacks has held roughly constant since 2009. Going forward, however, slowing demand growth for thermal coal means that this ratio may have to drop even further as companies forego potentially value-‐destroying investments in favor of returning more cash to shareholders.51 Engaging with thermal coal producers on these critical capital management decisions ought to be a top priority for shareholders concerned with carbon asset risk. Figure 18: Capex vs. dividends + share repurchases ("buybacks") by producer category, 2000-‐ 2013 49
For example, for the US this category includes three of the four largest coal producers (Peabody Energy, Arch Coal, and Alpha Natural Resources). 50
Note that neither of these is as high as the 2013 ratio for met coal producers, which was 7X. 51
Note that, in the short term, the deteriorating credit profiles for coal miners noted above may limit the ability to increase return of cash to shareholders. 22 Sep 2014 40 2014 Note: Values over capex totals (e.g. “3X”) reflect aggregate ratio across all three producer categories. Source: Bloomberg LP, CTI/ETA analysis 2014 22 Sep 2014 2014 41 Analysis of coal operations of four major diversified mining companies A comprehensive review of recent financial trends in the coal industry must examine large diversified mining companies that produce coal alongside other products such as iron one, copper, petroleum, uranium, and precious metals. We examine four large diversified mining companies (Anglo American, BHP Billiton, Rio Tinto, and Glencore Xstrata) that are major suppliers to global coal markets. With operations concentrated in Australia and South Africa (with additional mines in Colombia, the US, and elsewhere), these four companies control roughly 25% of production capacity for thermal coal export markets (and maintain a similarly large presence in met coal markets). Figure 19: Production profiles of large diversified miners, 2013 (Mt) Note: Value for Rio Tinto coal revenue includes a small portion of revenue attributable to uranium mining. Data reported by BHP refer to financial years, e.g. 2013 data refers to the period from July 2012 to June 2013. Source: Company reports, CTI/ETA analysis 2014 The figure above illustrates 2013 coal production and revenue derived from such production. Across these four companies, 2013 coal mining revenues ranged from $5.5-‐11.5 billion (with coal’s share of total company revenues ranging from 5-‐20%). Comparing against our sample of 83 pure-‐
play coal miners, average 2013 coal-‐related revenues for these four diversified companies of $8.5 billion are larger than 2013 revenues for 95% of the companies in our sample (i.e. all except for the four largest Chinese coal miners – Shenhua Energy, China Coal Energy, Shanxi Coal International, and Yanzhou Coal Mining -‐ as well as Coal India). Leaving aside Glencore Xstrata (formed in 2012 when commodities trading and production firm Glencore acquired diversified miner Xstrata, thereby significantly increasing Glencore’s coal holdings), over the past eight years coal’s contribution to total revenues has doubled at Anglo American while halving at Rio Tinto (and also declining at BHP Billiton). The paragraphs below examine how the profitability of these coal assets has evolved in recent years. 22 Sep 2014 2014 42 Figure 20: % of total revenue derived from coal for BHP, Anglo American, and Rio Tinto, FY 2005 – FY 2013 Coal contribution to total revenue
35%
30%
25%
20%
15%
10%
5%
0%
FY 2005
FY 2006
FY 2007
Anglo American PLC
FY 2008
FY 2009
FY 2010
BHP Billiton Ltd
FY 2011
FY 2012
Rio Tinto PLC
FY 2013
Note: Values for Rio Tinto coal revenue includes a small portion of revenue attributable to uranium mining. Data reported by BHP refer to financial years, e.g. 2013 data refers to the period from July 2012 to June 2013. Source: Bloomberg LP, CTI/ETA analysis 2014 22 Sep 2014 2014 43 M&A activity of diversified companies Sizeable balance sheets and global production portfolios make the four companies surveyed here among the most opportunistic buyers and sellers of mining assets, including coal mining assets. As existing coal reserves of these companies expose them to price and demand trends over a decades-‐
long time horizon, their merger and acquisition (M&A) activity with respect to thermal coal assets provides an interesting lens into how these companies view the medium and long-‐term economic prospects for coal, and in particular thermal coal. Figure 21: Reserve lifetimes at 2013 production rates –20-‐30 years of thermal coal Note: Estimate for Rio Tinto is combined across met and thermal. Reserves and production data from 2013 Annual Report adjusted to account for divestiture of Benga and Clermont mines; reserves and production data for Glencore Xstrata adjusted to account for acquisition of Clermont mine. Source: company reports, ETA/CTI analysis 2014 Recognizing that there are usually many influences on such decisions (including solvency and liquidity considerations), examining trends in the diversified companies’ purchases and sales of coal mines may illuminate how management of these companies views the medium and long-‐term prospects for the coal industry. One notable trend of recent years has been a divergence within this group in merger and acquisition (M&A) activity related to thermal coal. Specifically, whereas Rio and BHP have taken to divesting thermal coal assets, Glencore Xstrata has been actively buying thermal coal mines. With the exception of Rio’s 2010 acquisition of thermal/semi-‐soft coking coal prospects in Mozambique in 2010 (which, as discussed below, Rio resold in early 2014 at a loss of $3 billion), over the last ten years Glencore has been the only one of these companies to acquire major new thermal coal mines (sometimes, as described below, the very same mines that Rio and BHP are selling). 22 Sep 2014 2014 44 Table 9: Major coal-‐related dispositions by diversified miners, 2004-‐2014 Rank Date
Target N ame
10/25/13 Clermont Mine GS Coal Pty Ltd
Joint Venture
Rio Tinto PLC-‐
Arch Coal I nc
Jacobs Ranch
BHP Billiton Ltd-‐
Alam Tri Abadi PT
Maruwai Coal
Koornfontein Coal Optimum Coal Mine
Holdings Ltd
BHP Navajo Coal Navajo Tribal Co
Council
Riversdale-‐Coal International Coal Mine&Assets
Ventures
Elouera Colliery Gujarat NRE FCGL Coking Coal
Pty Ltd
BHP AU-‐Wyong Korea Resources Coal Project,NSW Corp
BHP Billiton Energy Investor Group
Coal South
BHP-‐Non-‐core Shareholders
Assets
Rio Tinto PLC-‐ Blair Linc Energy Ltd.
Athol 03/09/09 03/31/10 02/12/10 12/19/12 10/21/13 05/16/07 04/01/05 12/13/11 08/15/14 10/03/13 Acquiror N ame
Deal Size inc. Net Debt (million USD)
$1,015
Company Involved
Type of Coal Assets
Country
Thermal
Australia
$764
RIO (seller), GLEN (buyer)
RIO
Thermal
USA
$350
BHP
Met
Indonesia
$87
BHP
Thermal
South Africa
$85
BHP
Thermal
USA
$50
RIO
Met/Thermal
Mozambique
$40
BHP
Met
Australia
$13
BHP
Thermal
Australia
BHP (seller), GLEN (buyer)
BHP
Thermal
South Africa
Met/Thermal
RIO
Thermal
South Africa & Australia
Australia
Table 10: Major coal-‐related acquisitions by diversified miners, 2004-‐2014 Rank Date
Target N ame
02/02/12 Xstrata PLC
12/06/10 07/17/08 10/25/13 12/21/07 09/01/11 03/27/12 08/17/11 08/17/11 06/29/07 10/03/08 12/13/11 Acquiror N ame
Glencore International PLC
Riversdale Mining Rio Tinto PLC
Ltd
New Hope-‐New BHP Billiton Saraji Project
Mitsubishi
Clermont Mine Joint GS Coal Pty Ltd
Venture
Foxleigh Coal Mine Anglo American PLC
Optimum Coal Investor Group
Holdings Ltd
Optimum Coal Investor Group
Holdings Ltd
Peace River Coal LP Anglo American PLC
Peace River Coal LP Anglo American PLC
Wakefield Shanduka Investments(Pty)Ltd Coal(Pty)Ltd
Springlake Colliery Shanduka Coal(Pty)Ltd
BHP Billiton Energy Investor Group
Coal South
Deal Size inc. Net Debt Company Involved
(million USD)
Type of Coal Assets Country
$45,803
Met/Thermal
$3,661
GLEN (buyer), RIO (seller)
RIO
Met/Thermal
chiefly Australia & South Africa
Mozambique
$2,384
BHP
Met
Australia
$1,015
GLEN
Thermal
Australia
$620
AAL-‐LN
Met
Australia
$448
GLEN
Thermal
South Africa
$406
GLEN
Thermal
South Africa
$86
AAL-‐LN
Met
Canada
$74
AAL-‐LN
Met
Canada
$44
GLEN
Met/Thermal
South Africa
$17
GLEN
Met/Thermal
South Africa
GLEN (buyer), BHP (seller)
Thermal
South Africa
Source: Thomson One, ETA/CTI analysis 2014 22 Sep 2014 2014 45 Rio and BHP selling off and repositioning thermal coal mines The two companies that have done the most to unload thermal coal assets from their portfolios are Rio Tinto and BHP. In October 2013 Rio Tinto sold to Glencore for $1 billion+ its 50% stake in the Clermont mine in Queensland, Australia. In 2013 Rio production from Clermont amounted to nearly 6 million tonnes, accounting for 25% of Rio’s total 2013 thermal coal production; at the 2013 rate of production, Clermont’s marketable reserves were sufficient to last another 13 years.52 Moreover, Clermont was one of Rio’s lower-‐cost thermal coal mines, with a Newcastle-‐equivalent BECP of $56/tonne. Some observers have interpreted Rio’s sale of the Clermont mine to suggest skepticism about the medium-‐term economic prospects for thermal coal. The exit of Clermont from Rio’s portfolio came four years after a major divestment of assets held by Rio Tinto Energy of America (RTEA), a wholly-‐owned Rio subsidiary. From 2006-‐2008 RTEA was the third-‐largest coal producers in the US (on an energy-‐adjusted basis). In 2009, however, RTEA sold the Jacobs Ranch mine in the US Powder River basin to Arch Coal for $764 million. That same year RTEA also spun off three large surface mines in the Powder River Basin – Antelope and Cordero Rojo in Wyoming and the Spring Creek mine in Montana53 – into a separate entity (Cloud Peak Energy Inc.), which is now the third-‐largest US coal producer. Although Rio initially owned a 48% stake in Cloud Peak, in 2010 it subsequently divested this entire stake in 2010 via a secondary offering for Cloud Peak shares. Although at the time observers offered many rationales for Rio’s divestment of US thermal coal assets – including the need to pay down debt after a $38 billion acquisition of Canadian aluminum producer Alcan Inc. in 2007 – they served to significantly reduce production of thermal coal in Rio’s portfolio. Concurrent with unloading the Clermont mine in Queensland, Rio exited an ill-‐fated investment in Mozambique coal mines. In late 2010 Rio acquired two prospective thermal/met coal mines54 in Mozambique via its $3.6 billion takeover of ASX-‐listed Riverside Mining. At the time of the acquisition, making inroads into the Mozambique’s coal prospects seemed a way for Rio to substantially grow its production of coal (particularly met coal) in a region remote from the cost inflation pressures then affecting Australia (where Rio’s coal operations are concentrated). Subsequently, however, the economic logic for these mines eroded owing to (1) infrastructure barriers to exporting coal from Mozambique (in particular, the government’s refusal, on environmental grounds, to allow Rio Tinto to ship coal via barge down the Zambeze river); (2) a serious downward revision of the total coal resources in the Benga and Zambeze mines (which, by 2013, had fallen to one-‐fifth of their 2009 levels); and (3) civil unrest within Mozambique and resulting disruptions to production. In explaining Rio’s decision to sell off its Mozambique coal mines for 1.4% of its initial purchase price,55 analysts (quite understandably) generally emphasized one or more of the above issues.56 It is worth noting, however, that at the time of sale even Rio’s downwardly revised estimates of total met/thermal coal resources in the Benga and Zambeze mines 52
Rio Tinto,"2013 Annual Report," 212-‐215, 2014, http://www.riotinto.com/documents/RT_Annual_report_2013.pdf. 53
Liezel Hill, "Rio Tinto Sells Entire Stake in Cloud Peak Energy," Dec 22 2010, http://www.miningweekly.com/article/rio-‐tinto-‐sells-‐entire-‐stake-‐in-‐cloud-‐peak-‐energy-‐2010-‐12-‐22. 54
Much of the coal from the Benga and Zambeze mines – which Rio classified as “steam coal/semi-‐soft coking coal” – can generally speaking be sold into either the thermal or met coal markets. 55
Rhiannon Hoyle, "Rio Tinto to Sell Mozambique Coal Assets for $50 million," Wall Street Journal, July 30 2014, http://online.wsj.com/articles/rio-‐tinto-‐to-‐sell-‐mozambique-‐coal-‐assets-‐for-‐50-‐million-‐1406704712. 56
Reuters, "Rio Tinto pulls plug on ill-‐fated Mozambique coal venture," Jul 30 2014, http://in.reuters.com/article/2014/07/30/rio-‐tinto-‐mozambique-‐idINKBN0FZ0R220140730. 22 Sep 2014 46 2014 (2.3 billion tonnes) still equaled half of total coal resources from all 14 of its Australian mines57; coupled with the higher costs58 and longer timeframe for developing its Mozambique prospects, a bearish outlook on the medium and long-‐term prospects for thermal coal would certainly be consistent with the decision to sell these mines.59 In the same vein of potential retrenchment from thermal coal described above for Rio, over the past few years BHP has removed multiple thermal coal assets from its portfolio. As of writing (August 2014) BHP is in the process of spinning-‐off a collection of “non-‐core” assets that include its four remaining thermal coal mines in South Africa60, which in fiscal year 2013 (ending in June 2013) supplied 44% of BHP’s overall thermal coal production (31.6 of 72 million tonnes).61 The difference between the average Newcastle-‐equivalent BECP of these four mines ($74/tonne) and current spot prices for thermal coal (~$70/tonne for both the Newcastle and Richard Bay benchmarks62) suggests an immediate economic logic to these divestments; for fiscal year 2013 BHP’s South African thermal coal operations made a negative EBIT contribution of $34 million.63 They come, however, in the context of BHP’s moves over the past decade to reduce its exposure to thermal coal generally, and South African thermal coal in particular. Whereas ten years ago BHP produced approximately 40% of South Africa’s export thermal coal, the company has in recent years sold off major South African coal operations (e.g. via a 2010 sale of the Koornfontein coal mine to Optimum Coal Holdings and a 2011 sale of its Energy Coal South Africa assets to Glencore). In 2012 BHP also sold a major thermal coal asset in the US southwest (BHP Navajo Coal).64 Together with its pending departure from its South African thermal coal business, these moves amount to a significant downsizing of BHP’s core production base in thermal coal. Though it retains thermal coal assets in Colombia, Australia, and the US, recent asset sales and the proposed spin-‐off suggest a strong effort to reduce exposure to thermal coal. Beyond reducing exposure to thermal coal, the asset sales described above may be part of a strategy to reduce exposure to higher-‐cost thermal coal. In terms of 2014-‐2025 potential capex on thermal 57
Rio Tinto,"2013 Annual Report," 212-‐21. Through 2025, Wood Mackenzie's Global Economic Model suggests potential capex of $1.6 billion on the Benga and Zambeze mines, which had a Newcastle-‐equivalent BECP above $100/ton. Note that his capex figure does not include the substantial transport infrastructure-‐related costs described above. Energy Economics analysis based on data from Wood Mackenzie's Global Economic Model. 59
As to the purchaser of Rio’s Mozambique assets – India Coal Ventures Limited (ICVL)– it is relevant to note that this entity was set up by the Indian government with the express purpose of acquiring coal assets abroad to satisfy coal demand of India’s state-‐owned companies. Having guaranteed state-‐owned buyers makes ICVL’s financial considerations and sensitivity to long-‐term coal price trends significantly different from those of a private-‐sector commercial mining company. All Africa, "Vale looking to sell stake in Mozambican coal assets," Aug 4 2014, http://allafrica.com/stories/201408042728.html 60
Chad Bray, "BHP Billiton to Spin Off Units, Reversing Consolidation Trend," Aug 19 2014, http://dealbook.nytimes.com/2014/08/19/bhp-‐billiton-‐to-‐spin-‐off-‐assets-‐into-‐metals-‐and-‐mining-‐
company/?_php=true&_type=blogs&_r=0. BHP's four 4 thermal coal assets in South Africa (Khutala Colliery, Klipspruit Colliery, Middelburg Colliery and Wolvekrans Colliery). The spin-‐off will also house BHP's Illawarra, NSW coking coal assets. Note that at the time of writing BHP’s spin-‐off is being subject to legal review by South Africa’s government. 61
Brendan Ryan, "BHP Billiton eyes exit from thermal coal," Feb 11 2014, http://www.bdlive.co.za/business/mining/2014/02/11/bhp-‐billiton-‐eyes-‐exit-‐from-‐thermal-‐coal. 62
Note that the Richards Bay spot price is the primary spot price for export coal from South Africa. 63
Brendan Ryan, "BHP Billiton eyes exit from thermal coal." 64
Emily Guerin, "Navajo Nation's Purchase of a New Mexico coal mine is a mixed bag," High Country News, Jan 7 2014, https://www.hcn.org/blogs/goat/navajo-‐nations-‐purchase-‐of-‐a-‐new-‐mexico-‐coalmine-‐is-‐a-‐mixed-‐bag 22 Sep 2014 47 2014 58
coal mines with a BECP above $75/tonne, absolute exposure for Rio ($5.7 billion) and BHP ($4.6 billion) exceeds exposure for Glencore ($3.7 billion) and Anglo American ($1.8 billion).65 Hence, among the major diversified companies, these two companies at the moment have the most financially risky potential capex above key price levels related to thermal coal . Glencore Xstrata increasing its exposure to thermal coal Contrary to the path traveled by Rio and BHP, Glencore Xstrata is along among the four large diversified mining companies in having recently acquired significant new thermal coal assets. The most notable step in this direction came in 2012 when the giant commodities trading firm Glencore acquired diversified miner Xstrata for $45.8 billion. At the time of the acquisition, thermal coal accounted for 26% of Xstrata’s revenue. Both prior and subsequent to the Xstrata acquisition, however, Glencore has acquired other significant thermal coal assets. Most of this activity has centered on South Africa (where, as mentioned above, Glencore has come to own many of BHP’s former thermal coal assets). As of March 2014 such acquisitions had put Glencore in control of roughly one-‐quarter of South Africa’s thermal coal export production capacity.66 Outside of South Africa, Glencore has also added to its holdings of Australian thermal coal, chiefly via its purchase of Rio Tinto’s 50% stake in the Clermont mine. Moreover, analysts have recently reported on Glenore’s plans to invest $4.75 billion to increase coal production by 21% through 2016.67 Though deteriorating market conditions have led Glencore to shelve prospective investments such as a 35 Mtpa coal export terminal in Queensland68, overall Glencore has been unique among its peer group during recent years in actively increasing its exposure to thermal coal. In seeking to explain Glencore’s recent investments in coal, some analysts have noted that such counter-‐cyclical bets have been a hallmark of the large commodities trading firm. It is also worth noting that, as of 2013, coal production (thermal + met) accounted for only 5% of Glencore’s total revenues – one-‐half of coal’s revenue share for Rio and roughly one-‐quarter of the coal’s revenue share for BHP and Anglo American. Another explanation, however, is that the mines that Glencore has been acquiring are generally reasonably well-‐positioned on the cost curve, at least with respect to our estimate of a $75/tonne long-‐term equilibrium price in the seaborne export market. For example, the Clermont mine that Glencore acquired from Rio for $1 billion in 2013 has a breakeven coal price below $70/tonne. Recognizing this provides valuable context for analyzing Glencore’s recent acquisitions. 65
Energy Economics analysis based on data from Wood Mackenzie's GEM database. Brendan Ryan, "Glencore Xstrata eyes more SA coal," Mar 5 2014, http://www.bdlive.co.za/business/mining/2014/03/05/glencore-‐xstrata-‐eyes-‐more-‐sa-‐coal 67
Arjun Sreekuma, "Why this Billionaire Still Believes in Coal," Aug 20 2014, http://www.fool.com/investing/general/2014/08/20/why-‐this-‐billionaire-‐still-‐believes-‐in-‐coal.aspx 68
Kim Christian, "Glencore Xstrata scraps Qld coal terminal," May 13 2013 Xhttp://news.smh.com.au/breaking-‐news-‐business/glencore-‐xstrata-‐scraps-‐qld-‐coal-‐terminal-‐20130513-‐
2jhw6.html 22 Sep 2014 48 2014 66
4. Carbon Supply Cost Curves: methodology for coal markets 1) Defining “coal” The IEA observes that "coal is a generic name given to a wide range of solid organic fuels of varying composition (e.g. volatile matter, moisture, ash and sulfur content or other impurities) and energy content."69 In different publications the IEA classifies coal reserves and resources according to different terminology. The paragraphs below clarify each set of terms. Coal rank Coal is the altered remains of prehistoric vegetation that originally accumulated as plant material in swamps and peat bogs. The subsequent accumulation of silt and other sediments above the layer of peat, often initiated by movements in the earth’s crust (tectonic movements), buried these swamps and peat bogs, often to great depth. With burial, the plant material was subjected to elevated temperatures and pressures, which caused physical and chemical changes in the vegetation over many millions of years, transforming it into coal. The degree of ‘metamorphism’ or coalification undergone by a coal, as it matures from peat to anthracite, has an important bearing on its physical and chemical properties, and is referred to as the ‘rank’ of the coal. Coal is sub-‐divided into four main coal rank categories: • Anthracite (most metamorphosed) • Bituminous coal • Sub-‐bituminous coal, and • Lignite (least metamorphosed) While the four categories of rank provide useful reference groupings, it is noted that metamorphic changes result in a continuum of chemical and physical changes from peat, the precursor of coal, right through to anthracite. Low rank coals, such as lignite and some sub-‐bituminous coals, are typically softer, friable materials with a dull, earthy appearance; they are characterized by high moisture levels and a low carbon content, and hence a low energy content. Higher rank coals are typically harder and stronger and often have a black vitreous lustre. Increasing rank is accompanied by a rise in the carbon and energy contents and a decrease in the moisture content of the coal. Anthracite is at the top of the rank scale and has a correspondingly higher carbon and energy content and a lower level of moisture. BGR classification: hard coal and soft coal In its Resources to Reserves 2013 publication, the IEA divides coal into soft brown coals (lignite) and hard coals (bituminous and sub-‐bituminous coals) following the classification used by BGR, Germany’s Federal Institute for Geosciences and Natural Resources (a leading source of data and analysis on coal): • Hard coals have a heat content of at least 16.5 megajoules per kilogram and are essentially those most suitable for world trade. • Soft brown coals are those with high moisture and lower energy content, which are usually converted into electricity near the source of production. 69
IEA, WEO 2013, Box 4.1. 22 Sep 2014 49 WEO classification: steam coal (i.e. thermal coal), coking coal, lignite70 In its annual World Energy Outlook (WEO) the IEA breaks coal down into steam coal, coking coal, and lignite. • Steam coal accounts for nearly 80% of current global coal demand. It is mainly used for heat production or steam-‐raising in power plants (70%) and, to a lesser extent, in industry (15%). Typically, steam coal is not of sufficient quality for steel making. It is often referred to as thermal coal. • Coking coal accounts for around 15% of global coal demand. Its composition makes it suitable for steel making (as a chemical reductant and source of heat), where it produces coke capable of supporting a blast furnace charge. • Lignite accounts for 5% of global coal demand. Its low energy content and usually high moisture levels generally make long-‐distance transport uneconomic. Over 90% of global lignite use today is in the power sector.71 Recognizing different classification systems for coal, the figure below compares different systems: Table 11: Comparison of standard subdivisions and classifications of coal by coal rank Note: PCI = pulverized coal injection. PCI coal is used in steel production. Source: BGR, 2009. 2) Framework for Carbon Supply Cost Curves: Coal 2014-‐35 In our study we break coal Supply into the following categories: •
•
Metallurgical -‐ coking coal and Pulverized Coal Injection (PCI) Thermal or steam coal: 70
Definitions from IEA, WEO 2013, Box 4.1. The IEA notes that its lignite data includes peat. 22 Sep 2014 71
50 o
o
Export (Seaborne) Thermal Coal Domestic Thermal Coal Metallurgical We view metallurgical coal used for steel production as basically un-‐substitutable and hence whatever demand is projected to be for steel this will be met and there seems little point in challenging its production from a carbon prospective other than encouraging steel making efficiency on the demand side. We do include metallurgical coal in our carbon budget calculations 2014-‐35, but then separate out in order to emphasize the impact on thermal coal. Note, however, that thermal coal and metallurgical coal often co-‐exist within a single mine; moreover, certain varieties of coal – for example semi-‐soft coking coal – is often suitable for both thermal and metallurgical uses and be sold into either or both of these markets as prices dictate. Given the generally higher prices for metallurgical as opposed to thermal coal products, this co-‐production can affect mine economics; our data accounts for this and, when necessary, we adjust for such co-‐production in estimating the thermal coal production costs for a given mine. Thermal or steam coal • All data for supply cost curves and capital expenditure for thermal coal is mine based and comes from the Wood Mackenzie (WM) Global Economic Model (GEM) as of May 2014 – supplemented by minor additions from other WM data sources as indicated below • GEM is a coal data and discounted cash flow modeling package designed to facilitate coal asset “market valuations, M&A transactions, benchmarking, strategic planning and fiscal analysis.”72 • GEM contains 15 countries with cost data, so does not cover total world supply/demand • This leaves the following gap that also has to be estimated separately in terms of future supply in order to derive the carbon budget. For discussion, see below. 72
Wood Mackenzie: Global Economic Model -‐ Coal (brochure) 22 Sep 2014 51 Table 12: Wood Mackenzie country-‐level estimates for 2014 potential thermal coal production (Mtpa) Australia NZ Columbia Venezuela Chile Canada China (excludes lignite)* Mongolia Indonesia Vietnam Botswana Mozambique South Africa Russia US New Zealand Colombia Wood Mackenzie-‐modeled Total Global Thermal 2014 Mtpa 253 0 89 2 4 35 3,007 14 426 52 3 2 255 190 832 0 89 5,166 *Including China lignite would add another 367 Mt of capacity. Source: Wood Mackenzie, CTI-‐ETA analysis 2014 Table 13: List of thermal coal-‐producers not included in the GEM database and estimated 2014 potential thermal coal production for these countries (Mtpa) Indian production German domestic production Korean domestic production NZ domestic use Columbia's domestic use Poland production UK production North Korea Philippines Venezuela Mexico Malaysia Pakistan Unreported Indonesian exports Rest of world* Total 2014 Mtpa 529 5 2 3 4 70 14 41 8 3 14 3 2 72 137 907 *Rest of world (ROW) includes any countries not specifically identified in Tables 4 and 5 above. Source: IEEFA-‐ETA, 2014 22 Sep 2014 52 GEM incorporates a comprehensive set of cost, production and price data for each asset (historical and forecast through to the expected end of the life of the mine), as well as fiscal regime and currency exchange rate information to enable calculation of royalties and taxes. The asset and fiscal regime data is part of the ‘Wood Mackenzie Read-‐Only Data’ which users can adopt or copy and modify using different price assumptions etc. ETA employed Energy Economics to operate the GEM software and use it to generate the supply cost curves used in this report. Energy Economics used essentially unaltered the ‘Wood Mackenzie Read-‐Only Data’ (except for the creation of separate domestic thermal and export thermal projects as outlined below) during the course of this assignment -‐ adopting the Wood Mackenzie currency exchange rate and price assumptions unchanged. This was a conscious decision in order to retain clarity that the underlying core mine data was firmly based on the widely used Wood Mackenzie data set. GEM mine assets data set In addition to the standard set of assets provided as part of the Global Economic Model, Wood Mackenzie also provided data for an additional set of 155 potential mine projects ranked as ‘possibles’. This increased the total assets in the project to 1,431. Ownership data was not supplied for the ‘possibles’ assets, however Wood Mackenzie subsequently provided a list of the operators of these assets. In general, Energy Economics assumed that the operator of the project owned 100% the asset, however more detailed ownership data was entered by Energy Economics for some of the ‘possibles’ assets where available. All of our results are based on the full 1,431 asset data set. 3) The following geographies are considered: Importantly as we see the coal market as highly segmented and we solve for different approaches between domestic and export markets -‐ hence we cannot roll up to a single global supply curve as we did for oil. We segment as follows: i)
Domestic China, US and Rest of World as per WM coverage above ii)
Export-‐ Seaborne iii)
key export countries -‐ Australia, South Africa, Russia, Columbia, Indonesia, US 4) The following economics are considered: Cash costs Cash costs were calculated using Wood Mackenzie’s GEM mine valuation product.73 For each asset in GEM there are cash cost forecasts for each component of C1 costs (mining costs, processing costs, product transport, port and overheads) for each year of the expected life of a mine. These data are in asset spreadsheets that provide input for the GEM model, and form part of the ‘Wood Mackenzie Read-‐
Only Data’ discussed above. 73
Note that, in Wood Mac’s Global Economic Model, “cash costs” include both variable and fixed costs. For example, in Australia take-‐or-‐pay infrastructure costs are fixed for many operators, and these are incorporated into the cash cost estimates above. Likewise the component of a BECP over and above total cash cost is not necessarily a fixed cost – in the economic long run (prior to investment), this capital component is fully flexible. In the short run, where this increment represents sustaining capital, it is also likely to be variable. 22 Sep 2014 53 Royalties, on the other hand, are part of the output of the GEM model, because in many countries they are calculated as a percentage of the selling price of the coal produced by the mine. In order to model cash operating costs as accurately as possible, Energy Economics set up separate GEM projects for export thermal coal and domestic thermal coal. The domestic thermal and export thermal models were then each run separately to generate operating costs, including royalties, for each GEM asset. In most cases average cash costs were calculated in real terms over the period 2014 to 2035. Default GEM parameter settings were used except that ‘Economic Cutoff’ was disabled and calculation used real January 2014 terms rather than nominal terms. Break Even Coal Prices (BECP) The cash costs described in the preceding section are the most common parameter used in the coal industry to plot on supply cost curves. However, the future viability of a project is reliant on its capital costs as well as its cash operating costs and we believe from an investors perspective looking for a return on capital, is the most relevant. Hence, we have used the break-‐even coal prices (BECP) calculation module contained in GEM, which include capital costs, to further illuminate future project economics. The BECP’s are calculated such that, over the life of the asset, the net present value (NPV) of the asset is zero using a 10% discount rate – the default assumption in GEM This is a similar approach we used in our study on oil markets74 Default GEM parameters were used except that ‘Economic Cutoff’ was disabled. In calculating the BECP of existing assets, we use the "remaining life" parameter in order to account for development capital having been sunk. Calculating BECPs for thermal coal alone Many mines produce both metallurgical and thermal coal. In default mode GEM will calculate one break-‐even coal price for the mine (i.e. for mines that produce both metallurgical coal and thermal coal the break-‐even price will be the same for metallurgical coal and thermal coal.) There are two options in GEM to calculate a BECP for thermal coal only: 1. Fixing the metallurgical prices for the mine, and solving for thermal coal. This works well for mines for which thermal coal makes up a high percentage of production, but produces fairly extreme BECP outliers for mines that have only minor thermal coal production. More importantly Energy Economics believe that the resultant thermal coal BECP ends up having an unrealistic relationship with the fixed metallurgical coal prices for the mine. 2. Fixing the ratio of the metallurgical coal price to the thermal coal price. This is the method we chose; fixing the ratio at metallurgical price at 1.5 times the thermal coal price. All output was presented in US$/metric tonne It is noted that for mines that produce multiple products, there is a complex relationship between the thermal BECP, cash costs and price relativity assumptions. For mines that produce both metallurgical coal and thermal coal it is quite usual for the thermal BECP to be significantly below the cash cost of production, being counterbalanced by the metallurgical coal BECP being substantially above the cash cost. The thermal BECP is a better representation (than the cash cost) of the mix of metallurgical and thermal coal prices required to make an asset profitable. 74
Carbon Tracker Initiative and Energy Transition Advisors, Carbon Supply Cost Curves: Evaluating Financial Risk to Coal Capital Expenditures, September 2014, http://www.carbontracker.org. 22 Sep 2014 54 Hybrid BECP/production cost supply curves for domestic mines. GEM does not cater for calculating any further subdivisions of BECP beyond a thermal/metallurgical split – for example it is not possible to calculate a BECP specifically for domestic thermal coal. When using the “price adjustment mechanism” (detailed overleaf), the inability of GEM to create separate BECP’s for domestic thermal and export thermal is not a particular issue. The price adjustment mechanism compensates for this – with both export thermal and domestic thermal coal being converted to a like basis (Newcastle FOB equivalence) on the export curves. However for domestic mines which are only energy adjusted (not price adjusted) there were some issues to overcome in generating the domestic BECP curves. For mines that produced no export thermal coal, the thermal BECP is obviously valid for domestic thermal coal (as this is the only thermal coal product). But for mines that produced both export and domestic thermal coal the BECP calculated in GEM is an average of the two products and the energy adjustment does not compensate for this. Hence, hybrid curves were produced for the domestic thermal BECP graphs whereby; • For mines that produced domestic thermal coal but no export thermal coal the thermal BECP was valid for domestic coal and was plotted on the curve. This was also done for mines where export thermal coal made up less than 10% of the total thermal coal produced. • For mines where export coal made up more that 10% of the thermal coal produced, the total of domestic thermal cash costs (C1 plus royalty) plus average capex per tonne for the mine was used as a proxy for the BECP. In calculating the capex -‐ outlined below -‐ for the hybrid curves, Energy Economics used the period 2014-‐2045 to calculate the average capex per tonne for the mine. This was in order to produce a realistic capex figure for mines that were scheduled for construction late in the 2014-‐2035 period (during which period they would have very high capex and very low production). This was done to make the data more closely synchronized with the BECP, which (being calculated on a discounted-‐cash-‐flow basis) takes into account capex over the life of the mine. 5) Bringing the data to a comparable and comprehensive basis In order to make the different types of coal comparable on a cost curve it is necessary to make the following adjustments. Energy Adjustments All of the supply curves in this report, apart from the export thermal BECP curves, are presented on an energy adjusted basis to 6,000 kilocalories per kilogram on a net-‐as-‐received basis. This is a common reference energy content consistent with bituminous coals export from the Port of Newcastle, Australia, and is a commonly used standard and a key benchmark for global comparisons (this is similar to adjustment to a “Brent-‐equivalent price” for oil analysis). The energy adjustment is carried out to remove distortions to the curve that would otherwise occur when plotting high energy bituminous coals on the same supply curves as lignite, which has less than half the energy content. In calculating the energy adjustment Energy Economics used the following factors to apply to the various ranks of coal designated in the GEM data set. Table 14: Net energy contents used to energy adjust supply curve costs (kcal/kg) 22 Sep 2014 55 Coal Rank Anthracite Bituminous Sub-‐bituminous Lignite Export 6,690 6,000 4,780 2,630 Domestic 6,690 6,000 4,780 2,510 Source: Energy Economics Price-‐ratio adjustment – an innovative approach for export markets GEM contains WM price assumptions for each product produced by each mine, with the pricing point the same as the cost calculation delivery point (loaded-‐on-‐ship (FOB) for export coal and for domestic coal either mine-‐gate or delivered to customer). By taking a ratio of the average thermal coal price realized for a mine to the Newcastle benchmark this can then standardize the prices to the 6000kcal/kg NAR benchmark too. As a result using these price differentials we believe is an innovative way of incorporating energy differences, transport differentials and market location differences in the most comprehensive manner available. In effect a more holistic adjustment, taking into account coal quality issues and regional market differences. The WM price assumptions reflect the depressed pricing that has prevailed in Atlantic markets over most of the past seven years. Hence this method results in quite sharp upward adjustment of BECP prices for coal supplied out of countries such as Colombia, to put them on a par with Newcastle coal. We have utilized the WM price assumptions unchanged, but note the recent trend toward greater equivalence between Atlantic and Pacific market thermal coal spot prices. This approach does not make sense for domestic markets in our view. Only the simpler energy adjustment does. Introducing the Price Ratio Adjustment for export markets means the BECPs reflect the relative costs of delivery to market at a comparable energy content. This is comparable to a Brent Break Even Oil Price in the oil sector, which more readily uses this analysis. Example BECP with price ratio adjustment – export market Each mine can have up to six different brands of thermal coal in GEM. GEM has prices and volumes associated with each of these production streams. The prices attached to each brand take into account the energy content of the coal, but also adjust for coal quality issues and regional market price variances. For example, the FOB price for a coal exported out of South Africa may have a price a few dollars higher than an identical coal exported out of Australia, due to an ocean freight advantage into Europe. The idea is to calculate an average thermal coal price for the mine (tonnage weighted), express that as a proportion of the Newcastle benchmark price, then adjust the raw BECP for the mine by that proportion. e.g. Example project: Surat Basin, Australia Newcastle reference price: $79.28 WM price estimate for Project (one product only in this case): $70.56 Adjustment factor: $79.28 / $70.56 = 1.12 Raw BECP for Project: $85.51 Project BECP adjusted to benchmark equivalence: $85.51 * 1.12 = $96.08 22 Sep 2014 56 6) Generating a BECP & Cash Costs Carbon Supply Cost Curve for thermal coal We then develop the following structure: 1. Time frame 2014-‐35 -‐ in line with IEA 450 PPM. We do not believe that the coal industry forecasts coal supply in aggregate seriously beyond that date. WM GEM has China supply modeled out to 2035. 2. Geographies – as per above, China domestic, US domestic, ROW domestic and export markets, including major export countries 3. Potential coal supply based on ALL supply types – existing + highly probable + probable + possible in millions of tonnes per annum average over 2014-‐35 (MTPA) 4. Energy Adjusted BECP and cash costs for domestic markets 5. Price Ratio Adjusted BECP and cash costs for Export markets 6. A carbon conversion from MTPA volume to GtCO2 -‐See below 7) Reference 2°C carbon budget for coal To calculate our reference carbon budget for coal, we follow the approach below: Reference 2050 carbon budget for all fossil fuels (and share for coal) • Global carbon budget for all fossil fuels to 2050 = 900 GtCO2 • Giving coal a 36% share of the 2050 budget (based on its emissions contribution in the IEA 450 Scenario) = 324 GtCO2 To align with the fact that Wood Mackenzie’s potential coal production capacity estimates for China are only developed to 2035, we have to curtail the carbon budget to this period. Under a 450 Scenario, total emissions from coal through 2035 = 229 GtCO2. • Removing met coal emissions of approximately 40 GtCO2 = 189 GtCO2 • 189 GtCO2 is the global number; budgets for export thermal coal (as well as for the domestic production of individual countries) will be a portion of this. There is significant variation in the levels of emissions per tonne of coal depending on the rank of coal (i.e. anthracite, bituminous, sub-‐bituminous, lignite, metallurgical). Even within these ranks there will be a range of carbon content, and the process used for combustion and its efficiency will also influence the actual emissions. For presentational purposes we have simplified the ratio of CO2 per Mtpa of coal at a macro level for the major cost curves. When this was tested against a version using specific coal rank CO2 factors there was not a significant variation from the linear proxy we are using. The approximation we have used is a conversion of 1.8 GtCO2 per tonne of coal, which is the approximate IPCC conversion factor for sub-‐
bituminous coal – the most common type of coal. For example: 1000 Mtpa x 23 years x 1.8 GtCO2/tonne = 41.4 GtCO2 over the 2013-‐2035 period This approach may need to be adjusted in order to be applied to more specific regions or projects where the distribution of coal ranks will not be similar to the global composition. We have applied the carbon budgets in proportion to current projections of demand under the scenarios used. This is purely indicative and does not represent any actual apportionment of the carbon budgets to 22 Sep 2014 57 specific regions or exported coal by any political process. We encourage users to apply their own projections of coal use levels and carbon constraints on the cost curves to understand the implications of a range of scenarios. 8) Intersecting reference thermal carbon budgets with supply curves to derive the “climate secure” BECPs and volumes of potential production We can then use these reference carbon scenarios to intersect with the Global supply curve in terms of allowable supply to reach the GtCO2 reference point by matching the GtCO2 to the Mtpa of potential production and reading off from that the BECP associated with that. As with our oil study we consider that the climate secure amount of potential supply or production. It also gives us a sense of where the coal price needs to settle in a total climate change solution sense. For instance comparisons of our demand forecasts with our supply curves, we see that through 2035 • the IEEFA base case clears the thermal export market at a BECP of roughly $75/tonne which is based on 850 Mtpa IEEFA demand forecast • Our 450 demand scenario clears the market at a price of roughly $72/tonne and yields a volume of 675 Mtpa. One conclusion from this is that reduced demand further to 450 scenario levels does not involve a major drop in the coal price due to the flatness of the curve. 9) Relating supply to demand – deriving the key BECPs for mine development GEM Coverage and Matching to IEA Crucially we are working to match the demand to the precise supply curves that we derive for the key thermal coal segments In doing this we look to test the demand assumptions of the industry against the key climate scenarios of the IEA. Crucially we then look at an IEEFA forecast for thermal coal demand that closely matches the supply by countries forecast by Wood Mackenzie. Therefore the necessary adjustments (discussed in section 3 above) are fully taken into account. Further this is matched to the precise cost curve under consideration in terms of geography. This allows us to see where the key BECP for developing new mines lies and hence the key risks being taken based on our forecasts. That is then used for our capex analysis. 10) Capital expenditures GEM allows us to identify the capital expenditures associated with new potential supply at the mine mouth based on the following four categories: 1) Existing mines – sustaining capex 2) Existing mines – new expansion capex 3) New, or yet-‐to-‐be developed mines – sustaining capex 4) New, or yet-‐to-‐be developed mines – new expansion capex In the study, we aggregate categories (1) and (2) as “brownfield” and (3) and (4) as “greenfield”. 22 Sep 2014 58 GEM further shows mine production as being either metallurgical coal or thermal coal. Where a mine produces a mixture of both. We have pro-‐rated capex between the two coal types by production volume. Capex analysis is shown for the period 2014-‐25 (as in our previous oil report), thereby narrowing down to the next 10 years or so. This is shown at a global level, and for the other key splits by geography identified above. We also then show the split in capex above and below the key BECPs by geography and determined by the demand intersection. This is further mapped to a company level. The amount of carbon associated with the capex Export markets, China and US domestic and ROW is shown over the coal production time frame of 2014-‐35 which relates to the 2014-‐25 capex period. 11) Infrastructure costs Finally, perhaps the most difficult task is to project the costs of required infrastructure for the transport of coal – rail and port. GEM records this for mines where the costs are known and attributable to the mine owners. However for mines that require transport infrastructure where the cost is not borne by the mine there is data on total costs but this is inclusive of cash costs, capital costs and the profit margin of the third party operator. We do not know how much and who is investing. This could be government, private and listed entities. Developing estimates of infrastructure costs would be a further detailed study which was beyond the scope of this analysis. For this reason we do not attempt to estimate this in any way at a mine level. However we do show the IEA’s estimates of total infrastructure expenditures as a reference point. In other words our capex is related to the mine owners at mine mouth plus any infrastructure assigned to them and so underestimates the total financially risk capex in the economy. 22 Sep 2014 59 5. Detailed Results of Carbon Supply Cost Curves Having explained our methodology for estimating supply and demand for thermal coal, we now review findings from our supply-‐demand analysis. We begin by focusing on the market for thermal coal exports, and then turn to key domestic markets. Figure 22: Trade flows in the thermal coal export market, 2012 Note: Values are not energy-‐adjusted and statistical differences have been corrected to match export and import flows; values must therefore be interpreted as indicative. "FOB" means "free-‐on-‐board" (i.e. excluding the freight cost of seaborne transport. "NAR" means "net-‐as-‐received." Source: IEA Thermal coal exports -‐ risks to production with a breakeven price above $75/tonne We begin by focusing on the market for thermal coal exports, which currently covers 18% of global thermal coal demand. The horizontal axis of the figure below shows potential average annual export thermal coal supply/production from 2014-‐2035 (in million tons per annum, or Mtpa); the vertical axis shows the free-‐on-‐board75 supply cost in terms of US$/metric ton. The blue curve reflects the "cash costs" of production, adjusted to an energy content of 6,000 kcal/kg on an NAR (net-‐as-‐received) basis; the orange curve reflects the breakeven coal price (BECP) of production. BECP values are on the orange curve reflect a "Newcastle-‐equivalent" price, which includes adjustments to reflect the relative costs of delivery to market at a comparable energy content.76 75
"Free on board" means excluding the freight cost of seaborne transport. Here "Newcastle" refers to the port of Newcastle, Australia, a major port for export of thermal coal to China and other nation nations. The Newcastle price is a major benchmark for export thermal coal prices. For more explanation, see our methodology section above. 22 Sep 2014 60 76
Figure 23: Potential global export thermal coal production, 2014-‐2035 (Mtpa) Note: BECP is breakeven coal price; NAR is net-‐as-‐received Source: Energy Economics, using Wood Mackenzie's Global Economic Model and IEEFA-‐ETA analysis Intersecting the supply curves are projections of thermal export coal demand through 2035 under (1) the IEEFA low-‐demand scenario (blue line); and (2) a 450 ppm scenario, consistent with a trajectory for CO2 emissions that limits to 50% the chance of a rise in global temperatures of more than 2 degrees C (green line). The IEEFA projection sees average annual thermal coal export demand through 2035 of 850 Mtpa; this is 150 Mt (15%) below likely thermal coal export demand in 2014, which we estimate will be roughly 1000 Mt.77 IEEFA’s projection results from detailed analysis of demand profiles for individual countries, with demand for imports being the marginal source of supply to meet whatever demand cannot be met from domestic production. Thermal coal export demand of 850 Mtpa intersects the BECP supply curve at a price of $75/tonne -‐ suggesting that production with a BECP above this level is likely to struggle to achieve profitability in a low-‐coal demand world.78 A long-‐term Newcastle-‐equivalent price for thermal coal exports of $75/tonne would be midway between the current Newcastle spot price of $68/tonne and the 2018 forward price of $82/tonne. $75/tonne is well below, however, the average 2008-‐2012 Newcastle price of $100+/tonne; this disparity increases the likelihood of unsatisfactory financial returns for many of the export-‐focused thermal coal mines that have been newly developed or expanded over recent years (or are currently being developed) on the assumption of continuing $100+/tonne prices in export markets. In our analysis below of export-‐related capital expenditures, we focus on this $75/tonne level as a key supply cost threshold. Under a 450 ppm scenario, 2014-‐2035 average annual export demand of 675 Mtpa is 29% lower than projected by the IEEFA forecast and yields an equilibrium BECP of $72/ton (i.e. very close to the current Newcastle price). That a 21% drop in demand is associated with only a 4% drop in price reflects how flat (i.e. price-‐elastic) the global thermal export coal supply curve is through its middle portions, with relatively small changes in price leading to significant changes in quantity supplied. In economic 77
Energy Economics Estimate On the cash cost curve (blue line), the intersected price is closer to $70/tonne. 22 Sep 2014 78
61 terms, this is a far more risky proposition for development when structural changes in demand are possible. Finally, note that the chart's second horizontal axis shows cumulative CO2 production through 2035 in billions of tonnes of CO2 (GtCO2). The IEEFA demand forecast of 850 Mtpa is associated with cumulative CO2 production of 34 GtCO2; this is equivalent to roughly 18% of the 189 GtCO2 global 2°C carbon budget for thermal coal through 2035 that we derived in the methodology section above. Demand in a 450 ppm scenario of 675 Mtpa is associated with cumulative CO2 production of 27 GtCO2 (or 14% of the 2035 global thermal coal 2°C carbon budget). Country-‐level breakdown of thermal coal export capacity above $75/tonne In our 2014-‐2035 supply curve for thermal coal export production, note that we find 62% of potential production to be above our equilibrium BECP of $75/tonne (i.e. 1433 Mtpa out of a total of 2296 Mtpa). The table below provides a county-‐level breakdown of where this capacity exists. Given that the global supply curve for thermal coal exports remains relatively stable from 2014 to 2035, the breakdown is similar to our results for the 2014 supply curve in table 3 above. Again, China accounts for the largest share of potentially unprofitable export capacity (in this case, 39%), with Indonesia being second (23%), followed by Australia (11%) and the USA (6%). More tellingly, in even country save for Colombia, South Africa, and Vietnam -‐ which, collectively, account for only 9% of total potential export capacity -‐ a majority of 2014-‐2035 thermal coal export capacity has a BECP above the equilibrium level of $75/tonne that we project for a low-‐coal demand world. This suggests that the financial losses to export producers from a smaller-‐than-‐expected thermal coal export market could be significant and widespread. Later we explore these implications in detail for several major exporters of thermal coal. Note that our price-‐adjusted BECPs are in terms of the Newcastle export price, which is a key benchmark for the Pacific market. As noted above, given current pricing assumptions for the Atlantic market, this can at times bias upward cost estimates for suppliers from the Atlantic market (e.g. Colombia). That said, we feel focusing on the Pacific is justified as this region (1) currently accounts for 75% of the global export market; and (2) is the source of the a large majority in projected demand growth for thermal coal exports. For example, the figure below shows Citi estimates that through 2020 the Atlantic Basin will see growth in supply (from Colombia and the US) but negative import growth (chiefly due to declining demand from the European Union). Figure 24: Atlantic Basin supply growth driven by Colombia in the near term and US in the medium term (LHS); and Figure 25: Structural decline in European demand to drive negative Atlantic Basin import growth (RHS) Source: Citi Research Though declining import demand in the Atlantic Basin will affect all suppliers, US exporters may be particularly exposed (given that Colombia exporters are generally lower down on the cost curve, as the table below suggests). 22 Sep 2014 62 Table 15: Breakdown of 2014-‐2035 potential export production capacity above $75/tonne average 2014-‐2035 potential export production (mtpa)
Australia
Botswana
Canada
Chile
China
Colombia
Indonesia
Mongolia
Mozambique
Russia
South Africa
USA
Venezuela
Vietnam
Total
Total
311
39
11
1
888
106
532
50
54
97
93
106
3
5
2297
country's export production > % of country's $75/t as % of total export global export production total above Total above > $75/t > $75/t
$75/t
158
51%
11%
38
99%
3%
11
96%
1%
1
100%
0.1%
565
64%
39%
26
25%
2%
326
61%
23%
49
99%
3%
54
100%
4%
81
84%
6%
39
42%
3%
79
75%
6%
2
82%
0.2%
2
39%
0.1%
1433
62%
100%
Source: Energy Economics, using Wood Mackenzie's Global Economic Mode, CTI/ETA analysis 2014 For producers on the wrong end of the supply curve, cash costs will determine short-‐term behavior Commodity markets are dynamic, and how producers respond to being on the wrong end of the supply curve will in the short term vary depending on their relative cost profiles. Given a $75/tonne price for thermal export coal, producers with cash costs above this level should have a strong incentive to shut down production and limit losses. We find this to be at least 856 Mtpa of potential capacity, or 60% of potential capacity with a BECP above $75/tonne. Certainly, producers with cash costs below $75/tonne but BECPs above this level will in the short term have an incentive to keep producing so as to least cover a share of their fixed costs -‐ thereby exerting continued downward pressure on prices. We find this to be 578 Mtpa of potential capacity, or 40% of potential capacity with a BECP above $75/tonne. Unfortunately mine closures will be constrained by the costs of closing mines, take-‐or-‐pay contracts and decommissioning. Note that, particularly in the domestic markets we survey below, government interventions may alter the process described above. Policies such as financial aid to troubled coal producers -‐ or mandatory closure of mines in order to alleviate excess supply -‐ will affect company behavior. Domestic thermal coal markets -‐ key BECP levels of $53-‐65/tonne Given that 85% of the coal used today is consumed in the same country where it is produced and often close to the mine mouth so there is little transport, the impacts of future declines in thermal coal 22 Sep 2014 63 demand will in many cases be felt in domestic markets even more strongly than in export markets. We therefore analyze in detail thermal coal supply and demand trends in the two largest coal-‐consuming countries (China and the US) and at a high-‐level for the rest of the world. US domestic market for thermal coal -‐ $53/ton a key price level, but significant regional variation The past five years have been a rough time for US coal producers. 93% of total US coal consumption occurs in the electric power sector.79 Since 2008, coal consumption by US power plants has declined as a result of: 1. The 2008-‐2009 economic recession and increases in energy efficiency eliminating growth in US electricity consumption (with 2008-‐2013 retail electricity sales actually declining at a CAGR of 0.2%); 2. The shale-‐driven decrease in natural gas prices, with Henry Hub prices falling from an average of over $9/MMBtu in 2008 to under $4/MMBtu in 2013 and leading utilities to increase gas-‐fired generation at the expense of coal-‐fired generation; 3. Absence of development of new coal-‐fired plants (owing to weak economics and regulatory pressures) and closure of existing plants; 4. Increasing generation from wind and solar resources; and 5. Implementation of US Environmental Protection Agency (US EPA) regulations on air pollution from power plants, specifically the Mercury and Air Toxics Standards (MATS), the National Ambient Air Quality Standards, and the “Clean Power Plan” limits on carbon pollution.80 From 2008-‐2013 net electricity generation from US coal-‐fired power plants declined at a 4.4%, resulting in a level of 2013 US coal consumption that was 17% lower than the 2008 level (i.e. 839 million metric tonnes in 2013, versus over 1 billion metric tonnes in 2008). Summing the projected impact of renewable and gas-‐fired plant growth, coal plant retirements, and the EPA’s Clean Power Plan to reduce carbon pollution from existing power plants, Bernstein Research estimates that by the end of the decade coal burn by US power plants will decline by as much as 228 million short tons (i.e. 207 million metric tonnes)81; this decline is equal to one-‐quarter of 2013 consumption of coal by US power plants (or roughly one-‐third of 2013 US coal production). The projected decline in US coal burn is expected to result largely from closure of existing generating capacity -‐ with the US EPA projecting retirement of nearly 180 GW of coal-‐fired power generation capacity between now and 2020.82 79
US Energy Information Administration (EIA), "US Coal Consumption by End-‐Use Sector, 2008-‐2014," http://www.eia.gov/coal/production/quarterly/pdf/t32p01p1.pdf 80
For more discussion of these regulations, see CTI and IEEFA, Thermal coal demand: comparing projections and examining risks, Appendix C. 81
Bernstein Research, "Bernstein Energy & Power: The Coming Sea Change in Power Sector Coal and Gas Burn and Its Implications for Demand," September 2014. 82
The White House Press Office, "Presidential Memorandum -‐ Power Sector Carbon Pollution Standards", June 25 2013, http://www.whitehouse.gov/the-‐press-‐office/2013/06/25/presidential-‐memorandum-‐power-‐sector-‐carbon-‐
pollution-‐standards. US Environmental Protection Agency (EPA), "EPA Fact Sheet: Clean Power Plan," http://www2.epa.gov/carbon-‐pollution-‐standards/fact-‐sheet-‐clean-‐power-‐plan-‐overview. 22 Sep 2014 64 1200
140
1000
120
800
119
100
80
87
600
68
400
72
72
71
60
40
200
USD per t on
Million tons
Figure 26: US Total coal consumption and average annual CAPP spot price, 2008-‐2013 20
0
0
2008
2009
Electric Power Sector
2010
Other
2011
2012
2013
US Central A ppalachian coal spot price index ‡
‡ Prices are for CAPP 12,500 Btu, 1.2 SO2 coal, fob. Note: Volumes and prices above are in short tons (1 short ton = 0.907 metric tonnes) Source: EIA, CTI/ETA analysis 2014 Negative demand growth has led US coal producers to curb production, with annual US coal production falling 16% from 2008 to 2013 (i.e. from over 1100 million short tons in 2008 to 984 million short tons in 2013).83 Major US coal producers continue to shutter excess capacity, with Alpha Natural Resources (currently the seventh largest US coal producer by market cap) recently announcing plans to close eleven mines in West Virginia.84 These cutbacks in production, however, have been unable to prevent a decline US coal prices, with August 2014 spot prices for US Central Appalachian coal declining to $60/ton from an average 2008 price of nearly $120/ton. IEEFA long-‐term demand analysis projects that the US domestic thermal coal demand will continue to decrease at a 2% CAGR through 2035. As a result, expressed in metric tonnes (not short as is often the case in US markets), over the period, annual demand averages 600 Mtpa – 239 Mt (30%) below the 2013 level. This level of US thermal coal demand results in cumulative CO2 emissions through 2035 of 24.4 GtCO2 -‐ or 13% of the 189 GtCO2 2035 global 2°C carbon budget for thermal coal. We estimate that this level of thermal coal demand will, at a national level, result in a long-‐term equilibrium BECP for the US market of $53/ton. 15% of potential 2014-‐2035 domestic US coal production (i.e. 108.7 Mtpa or 717 Mtpa) has a BECP above this $53/ton level, with these mines concentrated in Northern and Central Appalachia as well as the Illinois Basin. Given significant regional variation in production costs and coal prices throughout the US, however, below we attempt to identify at-‐risk mines at a finer level of regional detail. 83
EIA, "US Coal Production, 2008-‐2014," http://www.eia.gov/coal/production/quarterly/pdf/t1p01p1.pdf. David Conti, "Emerald coal mine in Greene County to close next year," Trib Live, Aug 6 2014, http://triblive.com/news/adminpage/6568995-‐74/coal-‐emerald-‐alpha#axzz3CAkxkkGo. 22 Sep 2014 65 84
Figure 27: Potential domestic thermal coal production in the US, 2014-‐2035 (Mtpa) Note: BECP is breakeven coal price; NAR is net-‐as-‐received Source: Energy Economics, using Wood Mackenzie's Global Economic Model and IEEFA-‐ETA analysis In a 450 Scenario annual US domestic thermal coal demand through 2035 would average only 475 Mtpa (i.e. 364 Mt or 43% below the 2013 level). This level of average demand would produce cumulative CO2 emissions through 2035 of 24.4 GtCO2 -‐ or 13% of the 189 GtCO2 2035 global 2°C carbon budget for thermal coal. Such a downward demand shift would also reduce the long-‐term equilibrium BECP in the US market to $37.4/tonne (with 240 Mtpa of potential US domestic production capacity -‐ 34% of the total amount -‐ having a BECP above this level). Note that a scenario of low-‐coal demand (and certainly a 450 scenario) results in excess US coal supply above the level needed to satisfy domestic demand; in terms of average annual production through 2035, excess potential production ranges from 107 Mt (15% of total potential production) in the IEEFA low-‐demand scenario to 242 Mt (34% of total potential production) in a 450 scenario. This suggests greater pressure for US producers to increase exports of thermal coal, as happened from 2010-‐2012 (before reversing in 2013). We examine this possibility in more detail in the "major exports" section below. Adjusting for regional variation in US coal production costs and coal prices US coal production is grouped into several regional markets which are grouped around geological formations of coal of similar quality. As a result of differences in both geology and energy content of produced coal, the table below illustrates significant variation in supply costs throughout the US. 22 Sep 2014 66 Table 16: Regional variation in thermal coal production capacity and costs throughout the US Region Central Appalachia (CAPP) Potential thermal coal production capacity, 2014-‐
2035 (Mtpa) 33.6 % of total Cash Cost BECP potential ($/tonne) ($/tonne) production 5% 74.8 93.9 Illinois Basin (ILB) 192.2 27% 30.5 50.4 Northern Appalachia (NAPP) 81.5 11% 50.6 60.8 Powder River Basin (PRB) 335 47% 12.6 21.2 West Bituminous (WBIT) 58.4 8% 25 31.2 Other 16.1 2% N/A N/A Note: Figures for Cash Cost and BECP reflect regional weighted averages. Source: Energy Economics, using Wood Mackenzie's Global Economic Model and CTI/ETA analysis 2014 Such cost differences make it unlikely that each region will be affected equally by reduction in overall US coal demand. For example, Bernstein Research estimate that through 2020 EPA regulations will reduce US utility coal consumption by 185 million tonnes); the projected reduction in Western coal of 108 million tonnes (58% of the overall total), however, is 2.5X the projected reduction in Eastern coal of 41 million tonnes (22% of total), with the balance coming from decreased consumption of lignite of 35 million tonnes (20% of total).85 This partly reflects the reality that a majority of the US coal fleet exists in Eastern and Southern states. Despite having mine-‐level costs significantly lower than Eastern producers, the significantly greater expense of transporting coal from Western mines to these plants – which can equal the cost of the coal itself, and which our cost analysis does not take into account – will influence which mines bear the impacts of declining US coal demand. To attribute the low-‐demand scenario across regions we apportioned demand using SNL 2018 futures prices. This was done to reflect market sentiment about relative future demand shifts. The average SNL end-‐of-‐2018 futures price for each major supply region was converted for energy content, into 2014 US$ and from short tons to metrics tonnes to enable it to be plotted on our reference coal chart. Table 17: Approximating region-‐specific BECP levels using energy-‐adjusted 2018 forward prices Central Appalachia Northern Appalachia Illinois Basin Powder River Basin Energy Content (Btu/pound) 12500 13000 11800 8800 11400 Energy Content (kcal/pound) 3150 3276 2974 2218 2873 Energy Content (kcal/kg) 6945 7223 6556 4889 6334 Ratio to Newcastle 6000 kcal/kg 1.16 1.20 1.09 0.81 1.06 2018 spot price ($/short ton) -‐ various energy content Rockies 87 71.3 58.7 14.4 42.2 2014 Spot price ($/short ton) 77.4 63.4 52.2 12.8 37.5 Spot price ($/short ton) -‐ 6000 kcal/kg 66.9 52.7 47.8 15.7 35.5 74 58 53 17 39 Spot price ($/metric ton) -‐ 6000 kcal/kg Source: Price data from SNL, energy content from MIT, CTI/ETA analysis 2014 These prices were then used to determine the proportion of total 2014-‐2035 demand in the IEEFA scenario that would be met by supply from each region. The amount of supply sourced from each region 85
Bernstein Research, "Bernstein Energy & Power: The Coming Sea Change in Power Sector Coal and Gas Burn and Its Implications for Demand," September 2014, 6. 22 Sep 2014 67 depends on the amount of potential production under its region-‐specific BECP. For example, from Table 17 above, Central Appalachia has a BECP of $74/tonne; assuming that this the BECP of the marginal supplier, through 2035 production from this region will satisfy 14 Mtpa of demand (equivalent to 2.3% of total US demand over this period of 600 Mtpa). Comparing the totals in each row (e.g. 14 Mtpa) with potential total production in table 16 above (e.g. 33.6 Mtpa for CAPP) gives some indication of what portion of each region’s production may be at risk in a low-‐demand scenario. Table 18 Allocation of 2014-‐2035 US thermal coal demand by region in IEEFA scenario and regional threshold BECP level % of 2014-‐2035 demand sourced from each region Regional threshold BECP 2.3% (14 Mtpa) $74 31.1% (186.6 Mtpa) $53 8.3% (49.8 Mtpa) $58 Powder River Basin (PRB) 46.4% (278.4 Mtpa) $17 West Bituminous (WBIT) 9.0% (54 Mtpa) $39 2.9% (17.4 Mtpa) N/A Region Central Appalachia (CAPP) Illinois Basin (ILB) Northern Appalachia (NAPP) Other Note: Assumes average 2014-‐2035 demand of 600 Mtpa. Source: CTI/ETA analysis 2014 Ignoring regional differences, in the IEEFA low-‐demand projection of average 2013-‐2035 US thermal coal demand of 600 Mtpa marginal suppliers have a BECP of $53/tonne. Using the apportioned demand levels above, the chart below displays (1) potential 2014-‐2035 production for the US (on a BECP supply curve), with the circles highlighting each region’s portion of the supply curve; and (2) region-‐specific BECP of marginal suppliers from each region (e.g. “PRB -‐ $17”) -‐ adjusted for thermal value, US short tons converted into metric tonnes, and into 2014 US$ -‐ as calculated in the table above. Figure 28: Comparing potential US domestic thermal coal production against region-‐specific threshold BECPs Source: Energy Economics, using Wood Mackenzie's Global Economic Mode, CTI/ETA analysis 2014 22 Sep 2014 68 Adjusting for regional differences enables a more sophisticated analysis of risks to US coal production that one would get by simply applying a $53/tonne threshold price to the 2014-‐2035 supply curve. Region-‐specific analysis confirms the impression of risks to higher-‐cost producers in CAPP and NAPP; it also suggests, however, that a group of higher-‐cost suppliers of PRB and Western Bituminous coal may struggle in a scenario of declining US coal demand. China domestic coal market – ability to satisfy domestic demand with domestic production China dominates coal consumption; in 2013, China is estimated to account for nearly half of global thermal coal consumption.86 Coal consumption, in many ways, also dominates China; including both metallurgical and thermal coal, coal's 2013 share of China's total primary energy supply exceeded 67% (by way of comparison, coal's share of primary energy in the US is 20%).87 Despite being the leading importer of thermal coal (with 234 Mt of thermal coal imports in 201288), however, today over 90% of China's coal consumption is supplied via domestic production.89 Any analysis of global coal markets must therefore examine China's domestic coal production in detail. Relative to our other supply-‐demand analyses, for Chinese domestic production we adjust our methodology to account for the high degree of state ownership and involvement in the sector. Specifically, in determining a long-‐term equilibrium price level, we focus on the "cash costs" of production rather than on BECP levels. This reflects our view that the financial return expectations of state-‐owned (or quasi-‐state-‐owned) companies are likely to lower than those of private-‐sector companies (as state-‐owned enterprises often have other goals, such as protecting domestic jobs). Having said that, at the critical levels of demand, BECPs and cash costs are not too different Through 2035, the IEEFA low-‐coal demand scenario projects average domestic Chinese thermal coal of 3000 Mtpa (slightly below the 2013 demand level). This projection is the result of a variety of forces -‐ a change in the pace and composition of economic growth, increasing energy efficiency, rapid deployment of non-‐fossil energy sources -‐ altering the structure of Chinese coal demand.90 Average demand of 3000 Mtpa intersects China's cash-‐cost curve for domestic thermal coal production at a price of $60/tonne, in fact very close to the BECP at that level. In a 450 scenario, average demand of 2350 intersects China's cash-‐cost curve for domestic thermal coal production at a price of $48/tonne. Here the difference to the BECP is far more noticeable. 86
See Table 2 above. BP, BP Statistical Review of World Energy June 2014, “Primary energy consumption by fuel type,” 2014. 88
IEA, Medium-‐Term Coal Market Report 2013, 45. 89
CTI and IEEFA, Thermal coal demand: comparing projections and examining risks. 90
CTI and IEEFA, Thermal coal demand: comparing projections and examining risks. 22 Sep 2014 69 87
Figure 29: Potential domestic thermal coal production in China, 2014-‐2035 (Mtpa) Note: BECP is breakeven coal price; NAR is net-‐as-‐received Source: Energy Economics, using Wood Mackenzie's Global Economic Model and IEEFA-‐ETA analysis The carbon implications of domestic Chinese coal consumption merit special note. Even under scenarios or flat or declining consumption, the demand levels projected above yield cumulative 2014-‐2035 CO2 emissions of 94-‐120 Gt -‐ or 50-‐63% of the overall global 2035 2°C carbon budget for thermal coal. This underscores the massive climate implications of how China's coal consumption evolves over the next two decades, including policy. Likely trends in China’s thermal coal sector: exit of high-‐cost capacity, declining net imports Aside from underscoring the climate impacts of China's domestic coal consumption, two other interesting points emerge from our analysis. Under the IEEFA low-‐coal demand projection, note that 31% (i.e. 1342 Mtpa) of China's domestic thermal coal supply curve appears additional to what it needs in order to satisfy its domestic demand through 2035. This likely will have two major consequences. First, excess supply will accelerate the rationalization of Chinese coal production that has been underway since at least 2008. Currently in China's coal sector 50-‐70% of Chinese coal companies are losing money91 and inventories and unsold stocks at mines have reached record levels. In response, China's National Energy Administration has mandated the closure of 1,725 mines representing 117 Mt of combined capacity (i.e. ~2% of China's total coal capacity).92 Continuing over-‐supply will support further exit of capacity, particularly the smaller, higher-‐cost mines that sit at the right of China's supply curve. Additionally, ability to meet its coal consumption needs through 2035 with domestic supply suggests that China may soon cease to be a net importer of thermal coal. Having become a net thermal coal 91
Bloomberg News, "China to Fine Coal Miners Exceed Output Limits as Prices Drop," Aug 21 2014, http://www.bloomberg.com/news/2014-‐08-‐21/china-‐to-‐fine-‐coal-‐miners-‐exceeding-‐output-‐limits-‐as-‐prices-‐
drop.html 92
Analysts question whether this will do much to remedy China's supply-‐demand imbalance owing to (1) the small amount of capacity to exit; and (2) that many of these smaller, high-‐cost mines had already idled production in response to falling prices. 22 Sep 2014 70 importer in 2009, by 2012 China’s 234 Mt of imports accounted for 25% of global thermal coal imports.93 A steep reduction in Chinese imports will weaken the demand growth engine for seaborne thermal coal exports, particularly for China’s chief suppliers in Indonesia and Australia (two countries that together supplied 62% of Chinese thermal coal imports in 2012). In the short term China’s coal consumers (particularly in southern and coastal regions) may find continued incentives to import due to the generally lower level of international coal prices compared with domestic prices;94 further appreciation of China’s currency will enhance this incentive. Our supply-‐demand analysis, however, suggests that at the national level China’s continued status as the largest net importer of thermal coal may be short lived. For more discussion of this possibility, see our companion demand document.95 Finally, beyond simply decreasing imports, our analysis of capital expenditures below assumes that China may also become an opportunistic exporter of coal. Note, however, that we do not reach this conclusion by moving excess production from China’s domestic supply curve into export markets. Our coal supply analysis specifically distinguishes purely domestic potential production from production that has the potential to export. Even after fulfilling China’s domestic demand, purely domestic production cannot be switched over into export markets. Once domestic demand is fulfilled, however, there is then a potential to ship all potential export production into export markets – subject to economic constraints (i.e. how production costs compare with available international prices) and the availability of sufficient port and rail infrastructure. This is a key methodological nuance to bear in mind during our discussion of Chinese export potential. Domestic consumption outside of the US and China -‐ high-‐cost Indonesian supply Having covered the domestic thermal coal markets of the two largest consumers, we now turn to domestic consumption in the other thirteen countries included in Wood Mackenzie's GEM database – see above. Currently these rest-‐of-‐world (ROW) countries currently account for less than 20% of global thermal coal consumption. We term this group “WM ROW.” Through 2035, the IEEFA low-‐coal demand scenario projects average domestic WM ROW thermal coal of 520 Mtpa; this level of demand intersects the ROW supply curve at a BECP of $65/ton -‐$12/ton higher than the comparable value for the US and $5/ton higher than the comparable value for China. Note, however, that there is significant variation in costs across these markets. The average total is heavily influenced by Indonesia's large reserves of low-‐energy content, high-‐moisture thermal coal (which, on an energy-‐adjusted basis, translates into a higher cost of production). In a 450 scenario, average demand of 400 Mtpa intersects with the supply curve at BECP of $44/tonne. These two demand trajectories imply cumulative CO2 emissions through 2035 of either 16 GtCO2 or 21 GtCO2. 93
IEA, Medium-‐Term Coal Market Report 2013, 45. Constrained rail transport from China’s coal-‐producing northern provinces increases the cost of transporting coal to consumers in the southern and coastal provinces; as a result, particularly given the recent appreciation of China’s currency, such consumers can often source coal internationally at prices lower than China’s domestic coal prices. Citi, for example, notes that “truck deliveries of coal make up a large portion of the delivered cost of coal because of multiple tolls and high diesel fuel prices, among other cost components. Larger miners in China, along with the continued reduction in bottlenecks in the transportation network, could push out foreign coal imports.” Citi, “The Unimaginable: Peak Coal in China,” Sep 4 2013, 6. 95
CTI and IEEFA, Thermal coal demand: comparing projections and examining risks. 22 Sep 2014 71 94
Figure 30: Potential domestic thermal coal production in WM ROW, 2014-‐2035 (Mtpa) Note: BECP is breakeven coal price; NAR is net-‐as-‐received Source: Energy Economics, using Wood Mackenzie's Global Economic Model and IEEFA-‐ETA analysis With a demand level implied by the IEEFA low-‐coal demand projection, 14% of WM ROW domestic potential production capacity is beyond the amount required to satisfy required demand. 71% of this capacity exists in Indonesia -‐ again, chiefly as the result of the country's low-‐energy content coal reserves. The aggregated nature of the chart above suggests the need for caution in interpreting the results for any one country too literally. That said, the outlook for Indonesia's domestic production -‐ over half of which is above the threshold $53/tonne level -‐ is quite different than the outlook for, say, South Africa. Despite both being major producers and consumers of thermal coal, South Africa's domestic production is concentrated on the lower half of the domestic WM ROW supply curve. Many other countries in this group resemble the situation of South Africa, with New Zealand, Mongolia, and Vietnam -‐ none, in absolute terms, a major coal consuming nation -‐ being the only countries other than Indonesia to have more than 10% of potential production above the $65/tonne BECP level. 22 Sep 2014 72 Table 19: Breakdown of potential domestic thermal coal production in WM ROW above/below $65/tonne BECP Australia
Botswana
Canada
Chile
Colombia
Indonesia
Mongolia
Mozambique
New Zealand
Russia
South Africa
Venezuela
Vietnam
Total
average 2014-‐2035 potential domestic production (mtpa)
country's domestic production > % of country's $65/t as % of total domestic ROW domestic production total above Total
Total above > $65/t > $65/t
$65/t
53.9
2.2
4%
3%
4.7
0.0
0%
0%
24.6
0.3
1%
0%
3.2
0.0
0%
0%
0.0
0.0
0%
0%
108.8
57.6
53%
71%
53.3
8.2
15%
10%
4.2
0.0
0%
0%
0.2
0.2
100%
0%
98.4
5.1
5%
6%
205.1
2.3
1%
3%
0.0
0.0
0%
0%
42.4
5.6
13%
7%
598.8
81.5
14%
100%
Source: Energy Economics, using Wood Mackenzie's Global Economic Model and CTI/ETA analysis Examining impacts for exporters of thermal coal at a country level In the IEEFA low-‐coal demand scenario, projected 2014-‐2035 average annual demand for export thermal coal amounted to only 36% of potential supply (i.e. 850 Mtpa of 2384 Mtpa). This implies risks to profitability for up to 64% of potential thermal coal export supply (i.e. 1584 of 2384 Mtpa). Demand growth in the thermal coal export market is poised to slow just as new sources of supply are coming online in both traditional exporters and relative newcomers to the thermal coal export market. Through 2035 the world has the potential to add 900 Mt of new thermal coal export capacity -‐ increasing global export production capacity by 60% (i.e. from 1483 Mtpa in 2014 to an average of 2384 Mtpa from 2014-‐
2035).96 Our analysis suggests that -‐ assuming many such projects proceed -‐ many are likely to struggle to achieve profitability without significantly higher thermal coal prices than we see today. 96
Energy Economics analysis using Wood Mackenzie Global Economic Model, 2014. 22 Sep 2014 73 Figure 31: Proposed large-‐scale additions to thermal coal export capacity Source: Goldman Sachs Global ECS Research The table below provides a brief snapshot of our analysis of key thermal coal exporters -‐ with the point being that in each case projected average 2014-‐2035 capacity below our key price of $75/tonne is less than total 2014 capacity -‐ suggesting the likelihood of downward price pressure and financial challenges for both higher-‐cost existing exporters as well as new entrants. Table 20: Comparing 2014 total potential capacity against 2014-‐2035 average potential capacity < $75/tonne Australia Colombia Indonesia Russia South Africa USA Total 2014 total thermal coal export capacity (Mtpa) 197 89 350 96 76 39 847 Avg. 2014-‐2035 thermal coal export capacity < $75/tonne BECP (Mtpa) 152.5 80 207 16 56.4 31.4 543.3 % of 2014 total capacity 77% 90% 59% 17% 74% 81% 64% Source: Energy Economics, using Wood Mackenzie's Global Economic Model and IEEFA-‐ETA analysis Note that the figures above for 2014 potential export capacity are energy-‐adjusted and include lignite (although relatively little lignite is exported). Below we survey historic data on exports from individual countries – note that these values are not energy-‐adjusted and exclude lignite -‐ hence cannot be directly compared to the figures on our charts United States Analysis of the US domestic coal market above noted how declining US coal demand increases the incentive of US producers to export thermal coal to foreign markets. During the past few years this dynamic has already come into play. From 2009-‐2012 US thermal coal exports more than doubled to over 50 million tonnes and $4.3 billion in revenue97, before declining in 2013 (and, data suggest, 97
EIA, "U.S. Coal Exports by Year, Quarter, and Customs District, 2002 -‐ 2013 (Quantity: short tons / Revenue: dollars)," http://www.eia.gov/coal/data.cfm#imports. Note that the 50 million tonnes number is not normalized 22 Sep 2014 74 continuing to decline in 2014).98 A majority of 2013 thermal coal exports from the US went to Europe (chiefly the United Kingdom, the Netherlands, and Italy), with only 15% reaching Pacific importers such as South Korea, Taiwan, India, Japan, and China. Figure 32: US thermal coal exports (left-‐hand side) and export revenue (right-‐hand side), 2002-‐2013 60.0
4.50
4.00
50.0
3.50
3.00
2.50
30.0
2.00
20.0
billion USD
Million tonnes 40.0
1.50
1.00
10.0
0.50
0.0
0.00
2002
2003
2004
2005
2006
2007
Exports (lhs)
2008
2009
2010
2011
2012
2013
Revenue (rhs)
Source: EIA, CTI/ETA analysis 2014 With 2012-‐2013 US exports accounting for only 6% or so global exports, US coal miners see plenty of room for expansion. Average 2014-‐2035 potential thermal export production capacity of 163 Mtpa is 4X the 2014 level of 39 Mtpa.99 Expansion of the US potential to produce export thermal coal is heavily concentrated in the Powder River Basin (PRB), a region in Southeast Montana and Northeast Wyoming that is a center of US thermal coal production. Five large PRB mines, four of which export some amount of thermal coal already, account for over 60% of the potential incremental export production capacity that the US is projected to add through 2035 (i.e. 73.5 Mtpa of 124 Mtpa). to any specific energy content and so, strictly speaking, cannot be directly compared to numbers in our supply-‐
demand analysis below. 98
Platts, "US coal exports total 6.5 million st in July, down 18%," Sep 4 2014, reports that "the 1.6 million tons of thermal coal that the US exported in July 2014 (most recent data available) was down 36.9% from July 2013." Note that 1.6 million short tons is 1.45 metric tonnes. 99
Based on analysis of data from Wood Mackenzie's GEM database. Estimates here of US potential thermal coal export production capacity are normalized to an energy content of 6,000 kcal/kg. 22 Sep 2014 75 Table 21: 60% of potential incremental US thermal coal export capacity from five large Powder River Basin mines, 2014-‐2035 Black Thunder North Antelope Rochelle School Creek Bull Mountain Spring Creek Total % of total incremental US capacity 2014-‐2035 Increase in thermal coal export production capacity, 2014-‐2035 30.3 19.8 12.8 5.8 4.7 73.5 Standardised BECP (Newcastle equivalent price), avg. 2014-‐2035 82.1 87.7 80.9 76.1 78.6 N/A 60% Source: Energy Economics using Wood Mackenzie’s Global Economic Model, CIT/ETA analysis 2014 Our analysis of the global market for thermal coal exports, however, questions the ability of the US thermal coal miners to profitably increase exports. Applying a threshold BECP of $75/tonne (that we derived from our global analysis of the thermal coal export market above) to the US supply curve for thermal coal exports yields average annual 2014-‐2035 exports of only 31.4 Mtpa; this suggests only 20% of potential capacity to be capable of profitably exporting. Figure 33: Potential export thermal coal production in the US, 2014-‐2035 (Mtpa) Note: BECP is breakeven coal price; NAR is net-‐as-‐received Source: Energy Economics, using Wood Mackenzie's Global Economic Model and IEEFA-‐ETA analysis Differences in the energy content of actual current US exports complicate the task of comparing our results with historic data. Even assuming relatively low average energy content for current US thermal coal exports100, however, would still suggest our projected average annual 2014-‐2035 level to be roughly 9 million tonnes (or 20%) below the current 2012 high for annual thermal coal exports. In other words, ambitious industry expansion plans notwithstanding, our analysis suggests that companies will struggle to profitably increase US thermal coal exports beyond current levels. As evidence of this, consider that the standardized, Newcastle-‐equivalent BECPs of the five large PRB mines in the table above range from $1-‐13/tonne above our $75/tonne key threshold. A large portion of this cost involves the expense of 100
i.e. ~5000 kcal/kg, consistent with the reference energy content of PRB coal 22 Sep 2014 76 transporting PRB coal to import buyers, a topic discussed in more detail below. One caveat to be added is that the supply curve for US export thermal coal is very flat (i.e. price-‐elastic) through its middle portions. In other words, small changes in prices may notably expand the potential for profitable export. Our supply-‐demand analysis above, however, concluded that prices for export thermal coal are unlikely to stabilize at the $100+/tonne levels seen from 2008-‐2011. As a result, while long-‐term prices somewhat higher than the $75/tonne in our low-‐coal demand scenario will certainly expand the scope for US thermal coal exports, at best the mines affected will achieve marginal profitability. Challenges of geography and infrastructure Aside from the possibility of low prices in the global export market, export growth ambitions for US thermal coal must contend with the twin challenges of geography and infrastructure. The Pacific region currently accounts for 75% of the global thermal coal market (in 2012, 681 of 887 Mt)101, a share that is projected to increase through 2035; as noted above, in 2013 only 15% of US exports went to the Pacific. Shipping coal to India or China from, for example, Australia or Indonesia costs less than shipping it from the west coast of the United States. Moreover, currently west coast ports are ill-‐equipped to handle a materially higher volume of coal exports. US thermal coal exports currently travel mostly through ports on the eastern or southern US (e.g. Baltimore, Norfolk, and Houston-‐Galveston), with western ports such as Seattle and Los Angeles (as well as several Canadian ports) playing a minor role.102 Figure 34: Destinations of United States (US) coal exports (combined met and thermal), 2002-‐2012 (left) and ports of US coal exports, 2002-‐2012 (right) Note: Includes both thermal and met coal exports. Source: US EIA, IEA Significantly expanding US coal exports to Asia, however, will require adding multiple new ports on the US west coast. In 2010, coal companies announced plans for six new coal export terminals in the US Pacific Northwest off the coasts of Oregon and Washington.103 Of these six proposals, by May 2013 two 101
IEA, Medium-‐Term Coal Market Report 2013, 41. EIA, " U.S. Coal Exports by Year, Quarter, and Customs District, 2002 -‐ 2013 (Quantity: short tons / Revenue: dollars)," http://www.eia.gov/coal/data.cfm#imports. 103
The Center for Media and Democracy, "Coal exports from ports on the west coast of Canada and the United States," http://www.sourcewatch.org/index.php/Coal_exports_from_ports_on_the_west_coast_of_Canada_and_the_Unit
ed_States. The projects in Washington included ports at Grays Harbor, St. Helens, Cherry Point, and Longview; the 22 Sep 2014 77 102
had been withdrawn and one project shelved, while proposals for one Oregon terminal and two Washington terminals. Regulatory hurdles, however, may derail at least one of the remaining proposals, as Oregon's Department of State Lands recently denied a mandatory permit for a proposed 8.8 Mtpa terminal at the Port of Morrow (a decision that the project's sponsor, Australia-‐based Ambre Energy, is now appealing).104 Overall, the period since 2010 has demonstrated not just the regulatory but also the substantial financial risks attached to development of coal export terminals. 2013 saw cancellation of five proposed coal export terminals not just in the Pacific Northwest but also on the Gulf Coast105 as well as the withdrawal/deferral of IPOs by two US coal producers with ambitious plans for exports.106 The analysis above suggests that companies that move ahead with remaining proposals will be exposing their investors to considerable long-‐term financial risks. Indonesia-‐ reckoning with oversupply No country has seen a greater impact from growth of the seaborne thermal coal market than Indonesia. Since 2000 Indonesia has increased its exports of hard thermal coal more than 7 times to over 400 Mt in 2013.107 Though the country accounts for less than 6% of global coal production, its share of the export thermal coal market is 40%, largely due to its status as the top supplier of thermal coal imports to both China and India.108 As a result of continued investment in new supply, from 2008-‐2013 Indonesian thermal coal exports grew by an average of 30 Mt annually. The Indonesian thermal coal export story, however, has recently entered into a somewhat gloomier chapter. Declining prices for both export and domestic coal -‐ partly a result of the phenomenal supply growth mentioned above -‐ are pressuring margins for Indonesian producers. Of the 11 large publicly-‐
listed Indonesian thermal coal producers that we later analyze, in 2013 seven had EBIT (earnings before interest and taxes) margins in the single-‐digits. In August 2014 Standard & Poor’s declared PT Bumi Resources (one of Indonesia's largest producers) in “selective default” owing to failure to make payment on a $375 million convertible bond.109 Times are even tougher for smaller miners producing low-‐energy content coal, which Citi analysts estimate could account for up to 30% of Indonesia's total coal Oregon projects included ports at Coos Bay and Boardman. Of these, the Cherry Point, Longview, and Boardman projects remain in play. 104
Ted Sickinger, "Ambre Energy, Port of Morrow, and State of Wyoming appeal Oregon's rejection of coal export terminal in Boardman," Sep 9 2014, http://www.oregonlive.com/business/index.ssf/2014/09/post_211.html. 105
Olsen, Kinder Morgan scraps Port Westward coal terminal proposal. Longview Daily News. May 8, 2013, http://tdn.com/news/local/kinder-‐morgan-‐scraps-‐port-‐westward-‐coal-‐terminal-‐proposal/article_c02584f6-‐b811-‐
11e2-‐be99-‐0019bb2963f4.html. Williams-‐Derry, The coal export bubble. Sightline Daily. August 6, 2013, Retrieved February 19, 2014, from http://daily.sightline.org/2013/08/06/the-‐coal-‐export-‐bubble/ Epps, Ambre Energy seeks early lease termination for proposed Texas coal terminal. SNL Financial. December 9 2013. Corpus Christi coal export terminal canceled. Clean Gulf Commerce Coalition, http://cleangulfcommercecoalition.org/wp Epps, Cline Mining backs out of deal to export coal from Texas port. SNL Financial. August 20, 2013. 106
Coal producer Armstrong Energy withdraws IPO, Nasdaq.com, July 25, 2013. Darren Epps, Chris Cline owned mines in Illinois Basin see drop in coal production in Q3 ’13, SNL, October 25, 2013. 107
In all country discussion notes that historic totals on thermal coal exports are not energy-‐adjusted and, if from the IEA, exclude lignite. Yoga Rusmana and Fitri Wulandari, "New Rules in Indonesia Require Exporters to Have Licenses," Bloomberg, July 24 2014, http://www.bloomberg.com/news/2014-‐07-‐24/new-‐rules-‐in-‐indonesia-‐
require-‐coal-‐exporters-‐to-‐have-‐licenses.html. 108
IEA, Medium-‐Term Coal Market Report 2013, 41. 109
David Yong, "Bumi makes second-‐attempt to avert $375 million bond default," Bloomberg, Aug 11 2014, http://www.bloomberg.com/news/2014-‐08-‐11/bumi-‐makes-‐second-‐attempt-‐to-‐avert-‐375-‐million-‐bond-‐
default.html 22 Sep 2014 78 production.110 Indonesia's government is attempting to alleviate excess supply by capping total 2014 coal production at 397 Mt, versus total 2013 production of 421 M, albeit with little success to date.111 Growth in export supply is also projected to decline to less than 20 Mt annually from 2014-‐2020. Such changes, combined with the recent weakening of the rupiah, may bolster short-‐term profits for Indonesia's coal miners. Longer-‐term, however, there are significant hurdles to profitably expanding Indonesia's thermal coal production. These hurdles relate to the (1) low energy content of much of Indonesia's remaining thermal coal and lignite reserves (which necessitates discounts in selling price; (2) location of future mine developments, which typically will be further inland (hence increasing the capex requirements for railing this coal to Indonesian ports); and (3) potential Chinese bans on imports of low-‐quality coal (which China is considering as a way to reduce air pollution from coal).112 As Indonesia's existing mines are replaced by costlier new developments and domestic Indonesian thermal coal demand more than doubles, our supply analysis estimates that through 2035 profitable Indonesian thermal coal exports may average only 207 Mtpa113 (which, ignoring differences in energy content, is less than half of Indonesia's 2013 exports). Given the looming consolidation in Indonesia's coal sector, ownership of profitable Indonesian coal mines is likely to be limited to a shrinking number of players. Figure 35: Potential export thermal coal production in Indonesia, 2014-‐2035 (Mtpa) Note: BECP is breakeven coal price; NAR is net-‐as-‐received Source: Energy Economics, using Wood Mackenzie's Global Economic Model and IEEFA-‐ETA analysis 110
Citi, "Global Thermal Coal: When Cyclical Supply Met Structural Demand," 31-‐32. http://www.bloomberg.com/news/2014-‐07-‐24/new-‐rules-‐in-‐indonesia-‐require-‐coal-‐exporters-‐to-‐have-‐
licenses.html Note that enforcement of this cap will be complicated by the presence of up to 60 Mt of unreported Indonesian exports. 112
http://timesofindia.indiatimes.com/home/environment/pollution/China-‐suggests-‐cap-‐on-‐coal-‐use-‐import-‐
curbs-‐in-‐draft-‐air-‐pollution-‐law/articleshow/42168590.cms 113
CTI and ETA, Carbon Supply Cost Curves: Evaluating Financial Risk to Coal Capital Expenditures. 22 Sep 2014 79 111
Australia -‐ record numbers of delayed or cancelled projects Recently overtaken by Indonesia as the world's largest exporter of thermal coal (on both a tonnage and energy-‐adjusted basis), Australia's supply of thermal coal has nonetheless been growing strongly. From 2013-‐2015 Citi predicts Australia's thermal coal supply to expand by 29 Mt (40% of global supply growth over this period), as "brownfield" expansions of existing mines (approved during periods of $90/tonne+ prices) are completed and producers with take-‐or-‐pay rail contracts seek to lower unit costs through increased production.114 More notable is the Australian growth that has not occurred -‐ as projects planned in earlier years are delayed or abandoned as a result of declining prices, infrastructure bottlenecks, and rising prices. As of 2010 Citi tabulated 55 thermal coal projects in Australia (mostly "greenfield" projects) with a combined capacity of 368 Mt (i.e. 2.6X Australia's 2010 thermal coal exports of 140 Mt). As of May 2014, however, only 15 projects (representing 74 Mtpa of capacity) had been completed, while 28 projects (representing 177 Mtpa of capacity) had been delayed or abandoned (with the bulk of the remaining projects having received approval but not yet commenced construction).115 To put that into perspective, the combined capacity of delayed/abandoned projects since 2010 nearly equals Australia's entire 2014 thermal export capacity. Table 22: Planned projects in 2010 v Current Progress by Volume (LHS) & planned projects in 2010 v Current Progress by Number (RHS) Project Status Delivered Construction Approved/Committed Ongoing Delayed Abandoned Total Thermal Capacity (Mtpa) 75 16 77 25 114 63 368 % Project Status 20% 4% 21% 7% 31% 17% 100% Delivered Construction Approved/Committed Ongoing Delayed Abandoned Total # of Projects 16 2 3 6 15 13 55 % 29% 4% 5% 11% 27% 24% 100% Source: BREE and Citi Research A primary barrier to expanding Australia's thermal coal exports is that current export levels are already stressing port and rail infrastructure in the states of Queensland and New South Wales (where 95%+ of Australia's coal is produced).116 The need to build new infrastructure increases capex requirements and return hurdles for new projects -‐ a point that our companion case study on the Galilee Basin brings into sharp relief. Leaving aside the financial burden of new transport infrastructure, capex for many Australian greenfield projects is rising as a result of the shift toward progressively deeper and lower-‐quality coal seams. Producer “strip ratios” measure the ratio of waste material to coal extracted. The figure below shows that from 1991 – 2014 strip ratios have been steady increasing for both metallurgical (“met” or “coking” 114
Citi, "Global Thermal Coal: When Cyclical Supply Met Structural Demand," 6. From 2015-‐2018, Citi estimates that Australian supply growth will decline to 16 Mt. 115
Citi, "Global Thermal Coal: When Cyclical Supply Met Structural Demand," 35. 116
CIBC, "Rio Tinto: To Be, Or(e) Not to Be," 57-‐59, June 3 2014. 22 Sep 2014 80 coal) and thermal coal -‐ for thermal, coal from a ratio of 8:1 in 1990 (i.e. 8 tonnes of waste to one tonne of coal) to 10:1 by 2000 to 12:1 by 2010 and now at 14:1.117 Because Australia’s shallowest coal seams closest to the coast have all been mined, cost of producing thermal coal is substantially higher today than it was even five or ten years ago. Despite increased focus of producers on operating efficiencies, costs may stay high (relative to historical standards) just as prices wrestle with structural downward pressure. Figure 36: Queensland coal mining strip ratios by product, FY91 -‐ FY14E Source: Queensland ROM Longer-‐term, Australia resembles Indonesia in having substantial potential new capacity that would be, largely, uneconomic at current prices. Assuming a price threshold of $75/tonne that emerges from our 2014-‐2035 supply-‐demand analysis, over the next 20 years Australia's potential export capacity is 152.6 Mtpa.118 The capex requirements of potential greenfield projects, however, preclude profitable development unless future prices stabilize near $100/tonne or above. Our companion supply analysis examines the implications of this for the many companies (including Whitehaven Coal, New Hope Coal, Yancoal Australia, Adani, GVK, BHP and Glencore Xstrata) with potential exposure to greenfield Australian thermal coal mines. 117
For comparison, current strip ratios for Indonesia's four largest coal miners -‐ who, it should be noted, typically mine coal of much lower energy content -‐ range from 4.4:1 to 10.7:1. Citi," Global Thermal Coal: When Cyclical Supply Met Structural Demand," 32, Figure 60. 118
CTI and ETA, Carbon Supply Cost Curves: Evaluating Financial Risk to Coal Capital Expenditures. 22 Sep 2014 81 Figure 37: Potential export thermal coal production in Australia, 2014-‐2035 (Mtpa) Note: BECP is breakeven coal price; NAR is net-‐as-‐received Source: Energy Economics, using Wood Mackenzie's Global Economic Model and IEEFA-‐ETA analysis 22 Sep 2014 82 Case Study – The Galilee Coal Basin (prepared by IEEFA’s Tim Buckley) A huge undeveloped coal basin in Australia -‐ development has global implications The Galilee coal basin in central Queensland, Australia is one of the largest untapped thermal coal regions in the world currently being developed. With eight huge coal projects proposed, the Galilee could potentially supply 272Mtpa of thermal coal for the global export market for the next 30-‐60 years.119 This would represent a 27% expansion in global seaborne thermal coal supply at a time when IEEFA is forecasting that thermal coal demand will contract by an average 15% to 850Mtpa over 2013-‐
2035. Such a dramatic increase in supply at a time of forecast declining global import demand would have dire consequences for the listed coal sector globally. Given most global coal companies are saddled with excessive financial leverage due to poorly timed acquisitions during the recent coal boom, a prolonged downturn would see a significant increase in coal company bankruptcies’ over the next five years. While the conclusion above suggests the Galilee would seriously weaken the already fragile global seaborne coal market, the implications are equally risky for the two leading proponents being championed by the Queensland Government, Adani Enterprises and the GVK family, both power conglomerates based in India. The capital cost of their proposed greenfield integrated coal-‐rail-‐port developments are estimated at US$14bn and US$9bn respectively. The capital cost is prohibitively high, reflecting the isolated and remote location of the Galilee. Any coal development requires the construction of 400-‐500km of greenfield railway line and a 60-‐70 Mtpa new coal port, not to mention complete the dredging of a new shipping channel through the Great Barrier Reef World Heritage Area. At the same time, the proponent needs to build a series of open-‐cut and underground mines to give each project saleable production of 30-‐40 Mtpa. The first successful developer will also need to build a commercial airport, plus a grid transmission line for 300km, plus overcome the massive water scarcity in the region and seal 90km of roads just to get into the area. While the huge capital cost is the overriding barrier to opening up the Galilee, once it is developed financing the project debt will remain a challenge. We estimate the cash operating margin of the project to be close to zero at current thermal coal prices around US$70/t (Newcastle benchmark 6,000kcal NAR fob) and at the CTI long term price estimate of US$75/t. While the proponents suggest this is a high quality coal deposit, the Environmental Impact Statements lodged by the proponents state that the coal is high in ash content (with most coal seams at 25-‐30%) and the thermal energy content of 5,200-‐
5,500kcal is 10-‐15% below benchmark. This suggests the Galilee coal is likely to be priced at a 30% discount to the Australian Newcastle benchmark. Adani has proposed India as the key destination, although IEEFA’s analysis of the electricity pricing structures of India would suggest this is not a commercially viable proposition on almost any of the recent power purchase agreement terms offered by the Government of India.120 GVK has more of a target into Asia and China. The proposed coal ban into Coastal China for coal with more than 15% ash could rule out the Galilee coal entirely, unless GVK can procure water currently not available in this arid area. While the financial and operating risks associated with these proposals are clear, the lack of a successful operating track record by either of the proponents is another key risk. Neither GVK nor Adani have any prior experience in operating any material business in Australia prior to buying into their respective projects over 2010-‐2011. Neither has ever successfully operated a large scale coal mine. We note Adani 119
Note that this 272 Mtpa estimate is sourced from IEEFA analysis. Tim Buckley, “Briefing Note: Indian Power Prices,” IEEEFA, May 6 2014, http://www.ieefa.org/briefing-‐note-‐
india-‐power-‐prices/ 22 Sep 2014 83 120
does have a potentially large coal mine it commissioned in Indonesia in 2009, but given the mine has consistently operated at only 30-‐40% of targeted capacity for the last five years, this does not auger well for Adani in the Galilee. We also note the operating track record of both proponents is less than ideal in India. GVK has commenced a multitude of greenfield developments across India, but has suffered a number of project over-‐runs on time and / or budget, or forfeited the projects entirely. Adani has achieved significant operating milestones, particularly having built the Mundra port into the single largest port in India over the last two decades. However, a multitude of environmental, social and governance issues have been raised in the process. Both Adani and GVK acquired these coal project proposals at close to the peak in the coal price in 2011. Adani paid Linc Energy a total of A$655m (US$600m) for the rights to the Carmichael project. Having invested close to US$3bn to-‐date in its Australian coal-‐related activities, the Adani operations in Australia are geared close to 100% and hence consistently loss-‐making.121 GVK has offered to pay Hancock Prospecting a total of US$1.26bn, delivering the later a six-‐fold return on their US$200m investment. One complication that has arisen is that the GVK family was unable to settle the final payment of US$560m due in September 2014, given the group has net debt eight times the current market capitalisation of equity. Whilst GVK’s management have consistently reported there is no financial difficulties with the group, a string of net losses over the last few years and the inability of the group to deliver on its plans to divest major assets would suggest there is some financial pressure emerging. IEEFA has released detailed reports on each of these proposals, “GVK: Stranded in the Galilee”122 and “Adani: Remote Prospects.”123 These reports expand upon the perspectives detailed above. 121
Michael West, “Adani’s Galilee Basin project ‘not commercially viable,’” Sydney Morning Herald, Sep 5 2014, http://www.ieefa.org/adani-‐not-‐viable/ 122
IEEFA, “Stranded: Alpha Coal Project in Australia’s Galilee Basin” June 19 2013, http://www.ieefa.org/report-‐
stranded-‐alpha-‐coal-‐project-‐in-‐australias-‐galilee-‐basin/ 123
IEEFA, “Remote prospects: A financial analysis of Adani’s coal gamble in Australia’s Galilee Basin,” Nov 25 2013, http://www.ieefa.org/adani_coal_report/ 22 Sep 2014 84 Russia -‐ all about rail If for Australian producers rail costs are an issue, for Russian producers they arguably are the issue. Russia's main thermal coal export mines are in the Kuzbass region of western Siberia. The low mining costs of these mines are offset by extreme rail haul distances (4,750 km to Murmansk and 5,450–6,000 km to Pacific coast ports); these distances lead to railway tariffs of up to $30/tonne, and all-‐in rail transport costs (railway tariff, fuel, and railcar rental costs) of up to $40-‐50/tonne. Aside from having to contend with long haul distances, Russia's rail infrastructure has been beset by persistent underinvestment. The IEA estimates an investment gap of $1.4 billion per year from 2006-‐2011 leading Russian authorities in 2011 to declare 7% of Russia's entire railway system to be a bottleneck, hampering transport.124 The IEA further projects no medium-‐term improvement on this score. The primacy of rail costs in Russian coal production makes the country's thermal export supply curve extremely flat. Recent prices have put Russia's export coal mines under considerable financial duress, leading some mines to close or curtail production, and the government to temporarily freeze rail tariffs. Through 2035, our companion supply analysis estimates that a price of $75/tonne would allow the profitable export of up to only 16 Mtpa (i.e. less than half of the country's 2014 potential export capacity -‐ 80%+ of which, as noted above, does not appear profitable at current prices even on a cash-‐
cost basis).125 In the short to medium term, however, there is the possibility for government aid (intended to protect jobs and local economies) to keep Russian production above this 40 Mtpa level. Figure 38: Potential export thermal coal production in Russia, 2014-‐2035 (Mtpa) Note: BECP is breakeven coal price; NAR is net-‐as-‐received Source: Energy Economics, using Wood Mackenzie's Global Economic Model and IEEFA-‐ETA analysis 124
IEA, Medium-‐Term Coal Market Report 2013, 48-‐51. CTI and ETA, Carbon Supply Cost Curves: Evaluating Financial Risk to Coal Capital Expenditures. 22 Sep 2014 125
85 Colombia Colombia is distinct from the other four exporters reviewed here in (1) supplying primarily to the Atlantic rather than Pacific market (in 2012 Colombia sent over 70% of its exports to Europe and over 20% to North and South America); and (2) having production concentrated in a few large, low-‐cost, surface mines, such as Cerrejon and El Descanso (which are largely controlled by multinational diversified mining companies). Our companion supply analysis estimates that over the next twenty years these two mines have the potential to achieve combined average annual production of over 70 Mtpa, with Colombia as a whole having the potential to produce closer to 80 Mtpa.126 Over this period Colombian exports may also increasingly go to Asia, as expansion of the Panama Canal enables more cost-‐effective shipping of Colombian coal to China. Figure 39: Potential export thermal coal production in Colombia 2014-‐2035 (Mtpa) Note: BECP is breakeven coal price; NAR is net-‐as-‐received Source: Energy Economics, using Wood Mackenzie's Global Economic Model and IEEFA-‐ETA analysis 126
CTI and ETA, Carbon Supply Cost Curves: Evaluating Financial Risk to Coal Capital Expenditures. 22 Sep 2014 86 South Africa In response to the emergence of the Pacific thermal coal export market, over the last decade South Africa has pivoted from sending less than 20% of its coal exports to Asia in 2003 to sending 85% in 2012.127 South Africa has, in particular, become an important supplier to the Indian market (which, like China, accepts lower-‐quality coal than do many European importers). Thanks to its competitive positioning on the global cost curve, our companion supply analysis estimates that with a price of $75/tonne South African potential thermal coal exports may decline to 56.4 Mtpa (relative to 2014 capacity of nearly 80 Mtpa).128 Despite competitive supply costs and a 30 billion tonnes of remaining reserves,129however, expansion of South Africa's thermal coal exports is constrained by (1) relatively limited remaining coal reserves in the traditional mining areas around the Witbank Coalfield; and (2) infrastructure bottlenecks (i.e. rail links to the Richards Bay Coal Export Terminal) that hamper development of other coal reserves such as those in the Waterberg coal field. Figure 40: Potential export thermal coal production in South Africa, 2014-‐2035 (Mtpa) Note: BECP is breakeven coal price; NAR is net-‐as-‐received Source: Energy Economics, using Wood Mackenzie's Global Economic Model and IEEFA-‐ETA analysis 127
IEA, Medium-‐Term Coal Market Report 2013, 44. CTI and ETA, Carbon Supply Cost Curves: Evaluating Financial Risk to Coal Capital Expenditures. 129
BP, BP Statistical Review of World Energy June 2014, “Coal: reserves". 22 Sep 2014 128
87 6. Analysis of 2014-‐2025 thermal coal capital expenditures – potential for $112 billion in non-‐China high-‐cost capex The supply-‐demand analysis above has indicated that the world's largest domestic thermal coal markets -‐ as well as the seaborne export market -‐ are likely to be in varying states of oversupply from 2014-‐2035. We now survey what this means for 2014-‐2025 potential capital expenditures (capex) to expand production of thermal coal. Note that all of the capex totals discussed below relate to projects that companies have the potential to develop, rather than to projects that they necessarily intend to develop. Therefore, in practice, actual capex committed to projects above a given price level may be considerably lower than the potential total. Note also that the full spectrum capex associated with potential production through 2035 will also extend out to 2035 (e.g. for "sustaining" capex on existing and new mines). We focus on the period of 2014-‐2025 in order to emphasize a timeframe that is more relevant to investors. In analyzing coal capex, we distinguish between: • capex to sustain and expand existing mines (i.e. “brownfield” projects) • capex to sustain and expand new mines (i.e. “greenfield projects”) Table 23: Potential production and CO2 emissions (2014-‐2035, and potential capex (2014-‐2025) from mines at all BECP levels Existing Mines % of total New Mines % of total Total 2014-‐2025 Capex (USD billion) 220 45% 268 55% 488 2014-‐2035 Production CO2 emissions (Mtpa) (GtCO2) 5,689 225 71% 71% 2,313 92 29% 29% 8,002 317 Note: Capex figures refer to capex at all levels of BECP Source: Energy Economics, using Wood Mackenzie's Global Economic Model and IEEFA-‐ETA analysis The level of capex on existing mines is lower than new mines, yet the related amount of production from existing mines, (and ultimately CO2 emissions), is more than double. Through 2035, potential production just from existing mines in the Wood Mackenzie universe -‐ including from expansion of existing mines -‐ is enough to satisfy 85% of projected global thermal coal demand in the IEEFA low-‐
demand scenario: adding production from low-‐cost new mines satisfies over 100% of projected demand. Moreover, including potential production from India and other countries outside the Wood Mackenzie database -‐ which we approximate as equal to nearly one-‐quarter of 2014-‐2025 global demand -‐ provides an additional buffer between potential supply and projected demand without development of higher-‐
cost new mines. In practice, geographic separation between existing mines and sources of growing demand provide an added impetus for development of new mines. That said, at a high level the above comparison indicates a weak macro-‐level justification for investment in new high-‐cost mines. The possibility of oversupply -‐ leading to low prices and erosion of returns for investments to expand thermal coal production -‐ provides the context for our analysis of capital expenditures below. 22 Sep 2014 88 Figure 41: Total potential thermal coal supply vs. projected demand in IEEFA scenario (2014-‐2035average Mtpa) 12,000
10,000
1,598
Mtpa
8,000
1,150
1,163
6,000
1,705
4,000
6,745
2,000
3,984
0
Potential Supply Projected Demand
Existing mines < threshold BECP
Existing mines > threshold BECP
New mines < threshold BECP
New mines > threshold BECP
New and existing mines outside Wood Mac universe
Avg. demand in IEEFA low-‐demand scenario
Source: Energy Economics, using Wood Mackenzie's Global Economic Model and IEEFA/ETA/CTI analysis Reflecting this, note that by 2035, average annual investment in coal mining is modeled as falling by 17% relative to the estimated 2013 level in the IEA New Policies Scenario, and by 42.5% in the 450 Scenario. Given that our capex data does not cover all global coal mining production, comparing IEA aggregate estimates with our more granular figures is challenging. That said, the IEA projections illustrate that -‐ even under assumptions about future coal demand growth more bullish than those in the IEEFA scenario -‐ investment in coal mines may decline from its current level.130 Note also the IEA includes figures on coal transport capex, which is 49% of total upstream coal capex from 2000-‐2013. Our data does not include such figures. billion USD (2012)
Figure 42: Upstream coal supply investment, historic data for 2000-‐2013 versus projected 2014-‐2035 average annual investment under New Policies and 450 Scenarios 90
80
70
60
50
40
30
20
10
0
40
15
16
19
19
22
22
27
31
33
32
34
34
31
33
33
35
41
38
14
20
21
27
Mining
34
36
35
42
43
40
8
33
23
Transport
Note: For 2000-‐2013 data, mining/ transport split estimated as 51%/49% based on IEA reported avg. for period. Source: IEA, CTI/ETA analysis 2014 130
As our capex data relates to potential production, it cannot be directly compared with IEA numbers. 22 Sep 2014 89 $230bn of potential capex over key cost thresholds -‐ chiefly from greenfield mines For four different segments of the global thermal coal market -‐ the domestic markets of China, the US, and thirteen other coal-‐producing countries (collectively described as WoodMac Rest of World), as well as the seaborne export market -‐ our supply-‐demand analysis above identified long-‐term marginal supply costs likely to prevail under a low-‐coal demand scenario. We expressed these key cost levels in terms of breakeven coal price (BECP) and, for China's domestic market, the “cash cost” of coal production; they ranged from $53/tonne for the US domestic market to $75/tonne for the export market. Combining across these four market segments, below we calculate 2014-‐2025 capex associated with production that exceeds these key price levels. Across all fifteen countries we find $488 billion of potential thermal coal capex, with $230 billion of this above these key price levels. China dominates both the overall capex total as well as the portion above key supply cost thresholds; given state involvement in China's coal companies, however, much of this will be financed via funds from internal operations and state-‐owned banks rather than commercial banks and capital markets (and hence be less relevant to our focus on carbon asset risk in private financial markets). Excluding China, there is a total of $112 billion of potential thermal coal capex that exceeds the key BECP levels of our low-‐demand scenario; this amounts to over half of potential capex outside of China. This is more a focus for investors in listed companies and the export markets dominate. Through 2035, this capex corresponds with average coal production of over 1000 Mtpa and cumulative emissions of 42 GtCO2. Figure 43: Total potential thermal coal capex (export and domestic), 2014-‐2025 (million 2014 USD) Of the brownfield mines below the key thresholds, there is 5689 Mtpa production which satisfies 85% of our forecast demand through 2035. Greenfield projects account for majority of financially risky capex The two figures below break down our global capex totals by brownfield and greenfield projects. Reflecting the generally higher costs required to develop new mines (as opposed to expanding existing ones), greenfield projects seeing a higher proportion of capex over key supply cost thresholds -‐ 61% (73% excluding China), versus 30% for brownfield projects (25% excluding China). This difference, combined with greenfield projects seeing a greater overall capex total, explains why greenfield projects account for the dominant share of financially risk capex over this period (71%, or 82% excluding China). 22 Sep 2014 90 Figure 44: Total potential “brownfield” thermal coal capex (export and domestic), 2014-‐2025 (million 2014 USD) Figure 45: Total potential “greenfield” thermal coal capex (export and domestic), 2014-‐2025 (million 2014 USD) 22 Sep 2014 91 $138 billion of potential export capex that is financially risky above key price levels -‐ 75% of it on greenfield projects For mines intended to supply the seaborne export market, we calculate $138 billion of 2014-‐2025 capex associated with potential production above $75/tonne BECP. This amounts to over three-‐quarters of total potential export-‐related capex and would lead to cumulative carbon emissions through 2035 of 56.8 GtCO2 (i.e. 30% of the global 2035 2°C carbon budget for thermal coal in total). Figure 46: Total potential export capex by BECP level, 2013-‐2025 (million 2014 USD) The chart below breaks down this $138 billion total by country and project type. Greenfield projects account for 75% of total export capex above $75/tonne BECP (i.e. $107 billion). This risky greenfield export capex is primarily slated to take place in China, three countries that already export significant quantities of thermal coal (Australia, Indonesia, and South Africa), as well as two emerging African exporters (Mozambique and Botswana). These countries will also have to develop rail and port connections if they are to increase exports as sufficient capacity is not in place. Perhaps the most high profile example is the Galilee Basin in Australia (for more analysis, see our companion demand report).131 Development of mines in this remote part of Queensland will require new rail connections to new ports inside the Great Barrier Reef. With respect to capex on existing mines, note that both China and Russia (due to very high transport-‐
related costs) have a significant proportion of potential export production from existing mines requiring over $75/tonne to breakeven. 131
Demand 22 Sep 2014 92 Figure 47: Potential export capex by mine phase (over $75/t BECP only), 2014-‐2025 (million 2014 USD) Of the $138 billion of capex on display in the chart above, the chart below shows over $100 billion of this to have a BECP over $95/tonne -‐ including roughly 75% of totals displayed for China and Australia, 50% for Indonesia, and 100% for Mozambique, Botswana, and Mongolia. Reasons for the high costs of these mines include challenging geologies, low-‐energy content coal, and long inland distances from export ports. These mines will likely see the greatest financial risk under a scenario of declining growth in thermal coal export demand. Figure 48: Potential export capex by BECP band (over $75/t BECP only), 2014-‐2025 (million 2014 USD) 22 Sep 2014 93 Companies exposed to potential capex on high-‐cost greenfield export mines Moving from the country to the company-‐level, the figure below displays companies with the largest absolute exposure to high-‐cost greenfield export mines. Note that in the case of China, due to data limitations we have analyzed potential production and capex at the province rather than the company level. Reflecting the country's potential transition from net importer to net exporter of thermal coal, Chinese regions feature prominently on this list (e.g. Shaanxi, Shanxi, Ordos). Bear in mind, however, that these figures reflect potential capex exposure, and will not necessarily all be carried out. Also present are four of the largest multinational diversified mining companies (Rio Tinto, BHP Billiton, Glencore Xstrata, and Anglo American) as well as one diversified industrial concern (Mitsubishi), that have greenfield coal mines concentrated in Australia and South Africa. The balance of the list comprises the Indian conglomerate seeking to develop Australia's Galilee Basin (GVK), several Pacific producers (such as Churchill Mining and Bandanna Energy), as well as companies seeking to develop prospective coal sites in emerging export countries (e.g. Asenjo Energy in Botswana). Figure 49: Potential “greenfield” export capex -‐ largest companies (and Chinese provinces) by capex on “greenfield” mines with BECP over 75/t, 2014-‐2025 (million 2014 USD) 22 Sep 2014 94 US domestic capex -‐ $14 billion of potential capex above $53/tonne Noting significant regional variation in coal prices and production costs, our analysis of the US domestic thermal coal market identified $53/tonne as the BECP of marginal producers in a 2014-‐2035 low-‐coal demand scenario. Through 2025, we find $14 billion of capex associated with such production, with just under two-‐thirds of this amount relating to Greenfield projects. Continuing with these investments risks mines generating returns near or below firms cost of capital. Figure 50: Potential US domestic thermal coal capex by BECP, 2014-‐2025 (million 2014 USD) In discussing higher-‐cost US potential production, we noted differences in production costs and coal prices throughout different regions of the US; we then used 2018 futures prices to estimate region-‐
specific threshold BECPs (which ranged from $17/tonne for the Powder River Basin to $74/tonne for Central Appalachia). Drawing on this analysis, the figure below shows company-‐level capex exposure to high-‐cost production using as the thresholds our regional BECP estimates Figure 51: Company exposure to potential high-‐cost given region-‐specific BECPs, 2014-‐2025 (million 2014 USD) 4500 4000 US$ (mn) 3500 3000 2500 2000 1500 1000 500 0 CONSOL Alpha Peabody Murray Cloud Peak Alliance Arch Patriot Terra Nova James River Company Exis}ng mines -‐ Sustain Exis}ng mines -‐ expand New mines -‐ sustain New mines -‐ expand Source: Energy Economics, utilising Wood Mackenzie's Global Economic Model and CTI-‐ETA analysis 22 Sep 2014 95 Companies with the largest exposure (e.g. CONSOL, Alpha Natural Resources) have a significant presence in the Appalachian Basin, where the costs of mining coal tend to be higher than in other major US coal-‐producing regions such as the Illinois Basin or Powder River Basin (though these other two regions tend to have higher transport costs, which our domestic analysis does not take into account). Murray Energy also is active in Northern Appalachia, as well as the Illinois Basin. Peabody Energy is the production leader in the Powder River and Illinois Basins. The only company with significant high-‐cost expansion capex -‐ Cloud Peak -‐ is exclusively a Powder River Basin producer. Figure 52: Potential USA export thermal coal capex by BECP, 2014-‐2025 (million 2014 USD) Source: Energy Economics, utilising Wood Mackenzie's Global Economic Model and CTI-‐ETA analysis As discussed in our supply-‐demand analysis above, the bulk of this high-‐cost US export production will come online in the Powder River Basin via expansions to existing mines such as Arch Coal's Black Thunder, Peabody Energy's School Creek, and Cloud Peak Energy's Spring Creek. New high-‐cost greenfield mines also exist in the Powder River Basin as well as the Illinois Basin. Note that actually exporting coal from many of these projects will require additional billions of dollars of investment in new West Coast port infrastructure. Moreover, note that many of the companies on the chart below (CONSOL, Peabody, Alpha Natural Resources) also appear on the chart illustrating capex on higher-‐cost US domestic production -‐ suggesting these firms appear to have doubled-‐down on selling relatively expensive coal to both US and foreign consumers. 22 Sep 2014 96 Figure 53: Companies with largest exposure to potential capex on “brownfield” US thermal coal export mines, 2014-‐2025 (million 2014 USD) Source: Energy Economics, utilising Wood Mackenzie's Global Economic Model and CTI-‐ETA analysis Figure 54: Companies with largest exposure to potential capex on “greenfield” US thermal coal export mines, 2014-‐2025 (million 2014 USD) Source: Energy Economics, utilising Wood Mackenzie's Global Economic Model and CTI-‐ETA analysis 22 Sep 2014 97 China domestic capex – potential for $50+ billion in financially risky capex As with much else related to coal, when it comes to China the numbers increase. In the previous section we considered a low-‐demand scenario for China's domestic thermal coal market through 2035. Under such a scenario, average annual demand is satisfied by marginal production with cash costs of $60/tonne (and, as it happens, a BECP of roughly $60/tonne as well).132 The figure below shows 2014-‐
2025 capex associated with production above $60/tonne to be $70 billion. Moreover, through 2035 the cumulative CO2 emissions associated with just this potential high-‐cost production would claim one-‐
quarter of a global 2035 2°C carbon budget for thermal coal (while China's total domestic coal production over this period would exhaust nearly the entire 2035 budget 2°C carbon budget for thermal coal). Figure 55: China domestic potential thermal coal capex by BECP, 2014-‐2025 (million 2014 USD) Below is a regional breakdown of potential capex on high-‐cost domestic Chinese production, most of which relates to new mines. Figure 56: China domestic potential thermal coal capex – largest provinces by capex with BECP >$60/t, 2014-‐2025 (million 2014 USD) 132
Given the closeness between the cash costs and BECP level of marginal Chinese suppliers under our low-‐
demand scenario, for consistency with our analysis of other countries we analyze Chinese capex data using a BECP threshold. 22 Sep 2014 98 China export capex -‐ $44 billion of potential capex above $75/tonne As slowing demand growth leads to persistent oversupply in China's domestic coal market (a situation that is already occurring), capex on export-‐focused mines will increase. Here we then have to switch to looking at the price-‐adjusted export curve (as purely domestic production, even with domestic demand fully supplied, is not feasible to be exported). Through 2025 we find $54 billion of potential capex on Chinese thermal coal export mines -‐ with $44 billion of this above $75/tonne, and $38 billion of this above $95/tonne. Potential capex for export of Chinese thermal coal relates to both new and existing mines. Figure 57: China potential export thermal coal capex by BECP band, 2014-‐2025 (million 2014 USD) Source: Energy Economics, utilising Wood Mackenzie's Global Economic Model and CTI-‐ETA analysis As in China's domestic market, provinces in the north of China account for a large share of potential capex on high-‐cost production; potential high-‐cost brownfield projects are concentrated in Inner Mongolia, Shaanxi and Shanxi, while potential high-‐cost greenfield projects are also in Shaanxi and Shanxi as well as Ordos. As noted above, these figures represent potential expenditures whose actual commitment will depend on, among other things, relevant economic and infrastructure constraints. Figure 58: China potential export thermal coal -‐ largest provinces by capex with BECP >$75t, 2014-‐2025 (million 2014 USD) 22 Sep 2014 99 Australia export capex – potential $33 billion on greenfield mines above $75/tonne Apart from China, Australia has the largest amount of potential capex in new mines for export above the $75/tonne price adjusted threshold. Out of $46 billion in total export capex through 2025, $33 billion is associated with greenfield projects that have a BECP above $75/tonne; of this amount, $25 billion require a BECP above $95/tonne. Such expenditures represent a major roll of the dice on continued high prices in thermal coal export markets. Figure 59: Australia potential export thermal coal capex by BECP, 2014-‐2025 (million 2014 USD) Source: Energy Economics, utilising Wood Mackenzie's Global Economic Model and CTI-‐ETA analysis In terms of company exposure to high-‐cost greenfield Australian export mines, at the top of the list is GVK, the Indian conglomerate seeking to develop Australia's Galilee Basin (with another Indian company, Adani, a close second).133 Also present are the five largest diversified mining companies (BHP Billiton, Rio Tinto, Glencore Xstrata, Anglo American, and Vale), major Chinese producers (Shenhua, Meijin, Yanzhou), Japanese industrial concerns (Mitsubishi and Itochu), as well as several domestic Australian producers (Hancock, Whitehaven). This suggests the financial risk associated with greenfield thermal coal mines in Australia to be widely distributed -‐ hence a key issue for investors to monitor. 133
For more discussion of these firms, see Galilee case study above. 22 Sep 2014 100 Figure 60: Australia potential export thermal coal capex – largest companies by capex on “greenfield” mines, 2014-‐2025 (million 2014 USD) Source: Energy Economics, utilising Wood Mackenzie's Global Economic Model and CTI-‐ETA analysis 22 Sep 2014 101 Potential Indonesian coal capex for export -‐ $7.5 billion on new high-‐cost mines Finally, the risk to greenfield thermal coal export mines observed for Australia also exists for Indonesia. The country may struggle to maintain current export levels as new mine options are further inland and of poorer quality. This combination of increased costs and lower prices means these new expansion options are not economic at current prices. Through 2025 potential capex on production with a BECP above $75/tonne equals $7.5 billion. Indonesian-‐based producers account for the lion's share of this high-‐cost capex. Table 24: Indonesia potential export thermal coal capex – largest companies by potential capex by mine stage, 2014-‐2025 (million 2014 USD) Existing mines -‐ sustain BECP >$75/t Existing mines -‐ expand BECP >$75/t New mines -‐ sustain BECP >$75/t New mines -‐ expand BECP >$75/t BEP Coal 0 0 578 2,168 MEC Holdings 0 0 170 1,500 Churchill Mining 0 0 150 1,500 Adaro Energy 209 21 184 239 Reliance ADA 0 0 120 151 Delma Mining 0 0 167 55 115 85 0 0 Pan Asia 0 0 14 180 Bumi Resources 5 4 40 130 Kangaroo Resources 0 0 76 79 Company Bayan Resources Source: Energy Economics, utilising Wood Mackenzie's Global Economic Model and CTI-‐ETA analysis 102 22 Sep 2014
© Copyright 2026 Paperzz