Steve Piper, S&P: Sizing the Domestic Market

This article was originally published in Issue 1, 2016 of American Coal magazine – read the full issue (and past issues) on the ACC website by clicking here.


Where is Coal Demand Headed?

By: Steve Piper, S&P Global Market Intelligence

Over several months of 2015, the market share of natural gas generation exceeded that of coal-fueled generation as a combination of mild heating season weather and retirement of coal plants nudged natural gas into the lead position toward the end of the year. With coal retirements largely behind, and cheap natural gas ahead, what production levels face the restructured coal markets?

Current situation – large natural gas surplus

Coal markets were in 2015 confronted with a severe demand shock coming from natural gas that traded below $3/mmBtu at Henry Hub and below $2/mmBtu in the Marcellus shale producing region. Since then, natural gas availability has grown continuously, and the surplus of gas in storage actually accelerated toward the end of 2015. Overall, the ’15-‘16 winter has again been mild. The EIA natural gas inventory report for the week ending Feb. 26 outlined a pull of 48 Bcf from storage. As with most weekly pulls this winter, the withdrawal was small in comparison to the five year average for the week. The storage surplus at that time is estimated at 666 BCF (Exhibit 1), putting total storage levels in record contention for natural gas inventories at winter’s end. Season-ending storage appears poised to come in at 2.4 TCF, similar to March 2012 levels when natural gas prices last fell below $2/mmbtu. To put the surplus level in perspective, there is enough additional natural gas in storage to supply the U.S. generation sector for nearly 26 days.


Exhibit 1. Natural gas storage surplus vs. Henry Hub price Source: S&P Global Market Intelligence

Looking ahead to mid-year, today’s natural gas pricing will spur significant additional demand from natural-gas fired generation, nearly 2.5 Bcf per day above 2015 levels. Combined with slower production growth from shale plays as a response to the low price environment, surplus natural gas in storage is expected to erode to a more manageable 200 Bcf by July or August. A more modest storage surplus combined with summertime demand should support Henry Hub spot prices higher than $2.50/mmBtu.

For coal, any rally in natural gas may come too late

Coal producers, at the same time, can take little consolation from the prospect of a summertime rally in natural gas prices. A Henry Hub price of $2.50/mmBtu, with a corresponding price at Leidy Hub below $2/mmBtu, provides virtually no headroom for higher coal prices and less opportunity for coal plants to run more often.

There is no question that the retirement of legacy coal-fired generation has played an important role in the coal market’s adverse fortunes over the last several years. Had these plants run at their historic operating levels S&P Global Market Intelligence estimates incremental demand of 50 Mtons per year.

But the retirements themselves are also driven in part by the relentless economics of low natural gas prices. Faced with low power prices and reduced utilization, many of these coal plants could not earn an adequate return on investments to comply with the EPA MATS rule. Many of the initial rounds of coal retirements took place in the PJM region, where natural gas prices have been the lowest, and where coal plants bidding in to unregulated markets had less assurance of cost recovery on environmental retrofits.

During 2012-2014, the pain of natural gas switching focused mainly on eastern bituminous coal in Central Appalachia, where declining production and rapidly increasing costs accelerated a loss of market to natural gas, even as Illinois Basin and Powder River Basin increased production. A high level of investment in increasingly non-competitive Central Appalachia mines was behind the financial distress of James River, Patriot Coal, and Alpha Natural Resources over the last two years. However as natural gas prices continued to decline from 2015-present, competition against coal has now become so widespread that no region is spared from market loss. This can be seen in the more recent distressed financial condition of Arch Coal, Peabody, and Foresight, producers with a high proportion of mines in the Powder River Basin and Illinois Basin.

In short, the surplus of shale-driven natural gas production is driving a radical restructuring of the U.S. coal business and coal markets, with implications for both coal and natural gas. We see today a new market reality in which the mutual interplay of coal and natural gas supply and prices creates more pronounced seasonal patterns of demand for coal (Exhibit 2). Natural gas will retain some of its traditional seasonality under normal winter conditions, but as power generation increases its share of total gas consumption, summer and winter pricing differentials may shrink significantly.


Exhibit 2. Coal production forecast to 2017 Source: S&P Global Market Intelligence

Central Appalachia production outlook

Central Appalachia is a region that faces continued decline, with only a limited ability to alter its cost structure to become more competitive with natural gas. As a result, we show steadily increasing prices in response to cost pressures from lower volumes (Exhibit 3). Producers may ultimately consolidate enough around high-volume steam coal mines to become competitive, or to create niche markets to build demand such as new regional minemouth coal plants such as Longview Power. But the trend over the next 2-3 years is for further production declines and a flat to increasing cost structure.

As steam coal operations in the region consolidate, regional production of metallurgical coal may also be impacted as shrinking economies of scale constrain met output. S&P Global Market Intelligence projects a cut in met coal production over the next 1-2 years before met markets re-align.


Exhibit 3. Central Appalachian production and price forecast to 2017 Source: S&P Global Market Intelligence

Powder River Basin production outlook

With higher volume production, PRB producers have greater ability to adjust pricing downward in response to natural gas, and it appears they will need every bit of that flexibility 2016-2017. S&P Global Market Intelligence’s current price projections call for flat to declining prices to preserve market share against essentially flat volumes moved to domestic steam markets (Exhibit 4). With a degree of spare production capacity, producers retain the ability to ramp up production to meet greater seasonal demand if it arises.


Exhibit 4. Southern Powder River Basin production and price forecast to 2017 Source: S&P Global Market Intelligence

Illinois Basin producers are in a similar situation to PRB, with excess production capacity and more ability to discount against natural gas. Price forecasts move higher in 2017 as demand from former CAPP users supports a greater level of demand than would have otherwise occurred (Exhibit 5), but very little growth in the steam market is expected 2018-2019, keeping a lid on prices during this period.


Exhibit 5. Southern Powder River Basin production and price forecast to 2017 Source: S&P Global Market Intelligence

In the longer term, a coal plant fleet that is static or slowly shrinking in size and ceding a portion of electricity demand growth to expanding renewables results in a smaller overall coal market than coal stakeholders envisioned 5-10 years ago. Appalachian steam coals – effectively priced out of the domestic market – will principally serve export and metallurgical demand going forward, with the possible exception of niche minemouth coal plants. Coal mines in Colorado and Utah face rapid decline as well, with few prospects domestically. Rockies-sourced coal will increasingly serve a specialty export market for low-sulfur bituminous users. The market share of producers in the Powder River Basin and Illinois Basin will grow to become the predominant suppliers of a lower-volume steam coal market.

Overall, S&P Global Market Intelligence estimates the domestic steam generation market in the long-term averaging 685 million tons per year, nearly 300 million tons per year lower than 2014 (Exhibit 6). This translates to a total production (including non-electric end users, exports, and metallurgical) of approximately 800 million tons per year. Years with a relative surplus of natural gas may trend lower while years with greater price support from natural gas may finish somewhat higher. If spreads between coal and natural gas move between $1.00-1.50/mmBtu in favor of coal, demand upside is estimated at 80-100 million tons. However the need for coal producers to add revenue as well as volume tends to result in higher spot prices in advance of coal/gas spreads reaching those levels. But this indicates the level of sensitivity coal now has to natural gas pricing and dispatch going forward.


Exhibit 6. Generation burn for coal vs. natural gas, 2010-2020 Source: S&P Global Market Intelligence

A significant retrenchment in coal markets appears inevitable. Both coal and natural gas markets are oversupplied today, with only slight prospects for relief from generation demand growth. This has caused them to enter into a direct zero-sum competition for generation market share. Natural gas producers have the initiative in this race to the bottom, but both coal and natural gas producers have reserves enough to remain in competition for the near future, such that a significant increase in the price of one can motivate a production response on the part of the other.


Steve Piper is Director, Energy Research S&P Global Market Intelligence (

31. May 2016 by Jason Hayes
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